10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

X	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2012
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________
		Exact name of registrants as specified	I.R.S. Employer
Commission File		in their charters, address of principal	Identification
Number		executive offices, zip code and telephone number	Number
1-14465		IDACORP, Inc.	82-0505802
1-3198		Idaho Power Company	82-0130980
		1221 W. Idaho Street
		Boise, Idaho  83702-5627
		(208) 388-2200
		State of Incorporation:  Idaho
		None
Former name, former address and former fiscal year, if changed since last report.

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  Yes  X   No  __

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). 

IDACORP, Inc.: Yes X No  ___  Idaho Power Company: Yes X   No ___

Indicate by check mark whether the registrants are large accelerated filers, accelerated filers, non-accelerated filers, or smaller reporting companies.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

IDACORP, Inc.:                                

     Large accelerated filer     X Accelerated filer Non-accelerated  filer   Smaller reporting company

Idaho Power Company:                                

     Large accelerated filer     Accelerated filer Non-accelerated  filer X Smaller reporting company

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).

Yes No X

Number of shares of common stock outstanding as of October 26, 2012:     

IDACORP, Inc.:        50,156,973

Idaho Power Company:    39,150,812, all held by IDACORP, Inc.

This combined Form 10-Q represents separate filings by IDACORP, Inc. and Idaho Power Company.  Information contained herein relating to an individual registrant is filed by that registrant on its own behalf.  Idaho Power Company makes no representations as to the information relating to IDACORP, Inc.’s other operations.

Idaho Power Company meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this report on Form 10-Q with the reduced disclosure format.

1

COMMONLY USED TERMS
The following select abbreviations, terms, or acronyms are commonly used or found in multiple locations in this report:
ADITC	-	Accumulated Deferred Investment Tax Credits
AFUDC	-	Allowance for Funds Used During Construction
BCC	-	Bridger Coal Company, a joint venture of IERCo
CAA	-	Clean Air Act
CO2	-	Carbon Dioxide
CSPP	-	Cogeneration and Small Power Production
EGUs	-	Electric Utility Steam Generating Units
EPA	-	U.S. Environmental Protection Agency
EPS	-	Earnings Per Share
FCA	-	Fixed Cost Adjustment
FERC	-	Federal Energy Regulatory Commission
FIP	-	Federal Implementation Plan
GHG	-	Greenhouse Gas
HAPs	-	Hazardous Air Pollutants
HCC	-	Hells Canyon Complex
IDACORP	-	IDACORP, Inc., an Idaho corporation
Idaho Power	-	Idaho Power Company, an Idaho corporation
Idaho ROE	-	Idaho-jurisdiction return on year-end equity
Ida-West	-	Ida-West Energy, a subsidiary of IDACORP, Inc.
IE	-	IDACORP Energy, a subsidiary of IDACORP, Inc.
IERCo	-	Idaho Energy Resources Co., a subsidiary of Idaho Power Company
IFS	-	IDACORP Financial Services, a subsidiary of IDACORP, Inc.
IPUC	-	Idaho Public Utilities Commission
IRP	-	Integrated Resource Plan
kW	-	Kilowatt
MD&A	-	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MW	-	Megawatt
MWh	-	Megawatt-hour
NOx	-	Nitrous Oxide
NSPS	-	New Source Performance Standards
O&M	-	Operations and Maintenance
OATT	-	Open Access Transmission Tariff
OPUC	-	Oregon Public Utility Commission
PCA	-	Power Cost Adjustment
PURPA	-	Public Utility Regulatory Policies Act of 1978
REC	-	Renewable Energy Certificate
SEC	-	U.S. Securities and Exchange Commission
SIP	-	State Implementation Plan
SO2	-	Sulfur Dioxide
Valmy	-	North Valmy Steam Electric Generating Plant
VIEs	-	Variable Interest Entities

2

TABLE OF CONTENTS
				Page
Part I. Financial Information
	Item 1.  Financial Statements (unaudited)
		IDACORP, Inc.:
			Condensed Consolidated Statements of Income	6
			Condensed Consolidated Statements of Comprehensive Income	7
			Condensed Consolidated Balance Sheets	8
			Condensed Consolidated Statements of Cash Flows	10
			Condensed Consolidated Statements of Equity	11
		Idaho Power Company:
			Condensed Consolidated Statements of Income	12
			Condensed Consolidated Statements of Comprehensive Income	13
			Condensed Consolidated Balance Sheets	14
			Condensed Consolidated Statements of Capitalization	16
			Condensed Consolidated Statements of Cash Flows	17
		Notes to the Condensed Consolidated Financial Statements		18
		Reports of Independent Registered Public Accounting Firm		37
	Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of
			Operations	39
	Item 3.  Quantitative and Qualitative Disclosures About Market Risk			68
	Item 4.  Controls and Procedures			69
Part II.  Other Information:
	Item 1.  Legal Proceedings			70
	Item 1A.  Risk Factors			70
	Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds			70
	Item 4.  Mine Safety Disclosures			70
	Item 5. Other Information			70
	Item 6.  Exhibits			71
Signatures				72
Exhibit Index				73

3

FORWARD-LOOKING STATEMENTS

In addition to the historical information contained in this report, this report contains (and oral communications made by IDACORP, Inc. and Idaho Power Company may contain) statements that relate to future events and expectations, such as statements regarding projected or future financial performance, cash flows, capital expenditures, dividends, capital structure or ratios, strategic goals, challenges, and objectives, and plans for future operations. Such statements constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, or future events or performance, often, but not always, through the use of words or phrases such as "anticipates," "believes," "estimates," "expects," "intends," "plans," "predicts," "projects," "may result," "may continue," or similar expressions, are not statements of historical facts and may be forward-looking. Forward-looking statements are not guarantees of future performance and involve estimates, assumptions, risks, and uncertainties. Actual results, performance, or outcomes may differ materially from the results discussed in the statements.  In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes to differ materially from those contained in forward-looking statements include those factors set forth in this report; IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, particularly Item 1A - “Risk Factors” and Part II, Item 7 - “Management’s Discussion and Analysis of Financial Condition and Results of Operations;” subsequent reports filed by IDACORP and Idaho Power with the Securities and Exchange Commission; and the following important factors:

• the effect of regulatory decisions by the Idaho Public Utilities Commission, the Oregon Public Utility Commission, the Federal Energy Regulatory Commission, and other regulators affecting Idaho Power's ability to recover costs and/or earn a reasonable rate of return;

• variable hydrological conditions and over-appropriation of surface and groundwater in the Snake River basin, which can impact stream flows and the amount of generation from Idaho Power's hydroelectric facilities and cause Idaho Power to rely more heavily on more expensive generation resources and market power purchases;

• the cost and availability of materials, fuel, and commodities, and their impact on Idaho Power's infrastructure costs, power costs, and ability to meet required loads, and their impact on the wholesale energy market in the western United States;

• costs and delays associated with construction and maintenance of power generation, transmission, and distribution facilities, including the inability to obtain required governmental permits and approvals, hydroelectric plant licenses under reasonable terms (and the costs resulting from conditions in such licenses), rights-of-way, and siting, and risks related to contracting, construction, and start-up;

• disruptions or outages of Idaho Power's generation or transmission systems or the western interconnected transmission system affecting Idaho Power's ability to deliver power to its customers and requiring the dispatch of more expensive generation resources or purchasing power, which may ultimately increase costs;

• increased costs associated with the legislatively mandated purchase of intermittent power, such as wind, at above-market rates, and the costs and other challenges of integrating intermittent power sources into Idaho Power's resource portfolio;

• population growth and changes in residential, commercial, and industrial growth and demographic patterns within Idaho Power's service area, the loss or change in the business of significant customers, and the associated impact on loads;

• the impact of changes in economic conditions in Idaho Power's service territory and elsewhere, including the potential for changes in demand for electricity, revenue from sales of excess energy, financial soundness of vendors and service providers, and the level of uncollectible customer accounts;

• changes in and costs of compliance with laws, regulations, and policies relating to the environment, natural resources, and endangered species and the adoption and interpretation of laws and regulations addressing greenhouse gas emissions, global climate change, and energy policies intended to mitigate carbon dioxide, mercury, and other emissions;

• climate change and weather variations, which affect customer demand and hydroelectric generation and can impact the ability and cost to serve customers;

• inclement weather and other natural phenomena such as earthquakes, floods, droughts, lightning, wind, and fire, which, in addition to affecting customer demand for power, could significantly affect the ability and cost to procure adequate supplies of fuel or power to serve customers, and could increase the costs to repair and maintain Idaho Power's generating facilities, transmission and distribution systems, and other infrastructure;

4

• transaction risks, including increases in costs, associated with Idaho Power's energy commodity and other derivative instruments, the failure of Idaho Power's energy risk management policies to work as intended, exposure to counterparty credit risk, and potential higher costs of hedging activities due to new regulations pertaining to swaps and derivatives;

• wholesale market conditions, including the volatility of prices and availability of power on the spot market and the ability to enter into commodity financial hedges with creditworthy counterparties, and the cost of those hedges, which may affect the prices Idaho Power must pay for power as well as the prices at which Idaho Power can sell any excess power;

• deteriorating values in the equity markets, changes in interest rates and credit spreads, reductions in demand for investment-grade commercial paper, inflation, and other financial market conditions, as well as changes in government regulations, which affect, among other things, the cost of capital and the ability to access the capital markets, indebtedness obligations, and the amount and timing of required contributions to benefit plans;

• failure of Idaho Power to comply with state and federal laws, policies, and regulations, including new interpretations and enforcement initiatives by regulatory and oversight bodies, including, but not limited to, the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation, the Western Electricity Coordinating Council, the U.S. Environmental Protection Agency, and Idaho and Oregon state regulatory commissions, which may result in penalties, increase the cost of compliance, change the nature and extent of costly investigations and audits, and increase the costs of remediation;

• the cost and outcome of litigation, dispute resolution, and regulatory proceedings, and penalties, settlements, or awards that influence the companies' business and operations;

• reductions in credit ratings, which could adversely impact access to capital markets and would require the posting of additional collateral to counterparties;

• the ability to obtain debt and equity financing or refinance existing debt when necessary or on favorable terms, which can be affected by factors such as credit ratings, volatility in the financial markets, the companies' financial performance, and other economic conditions;

• whether the companies will be able to continue to pay dividends under the terms of their respective financing and credit agreements and regulatory limitations, and whether the companies' boards of directors will continue to declare common stock dividends based on the boards of directors’ periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in applicable agreements;

• the potential effects of negative publicity regarding business practices, whether true or not, which could result in, among other things, costly litigation and a decline in IDACORP's common stock price;

• changes in tax laws or related regulations or new interpretations of applicable law by the Internal Revenue Service or state and local taxing jurisdictions, and the availability and use by IDACORP or Idaho Power of tax credits;

• employee workforce factors, including the ability to attract and retain skilled workers, unionization or the attempt to unionize all or part of the companies' workforce, the ability to adjust the labor cost structure to changes in growth within Idaho Power's service territory, and increasing health care and other benefit costs;

• the failure of information systems or the failure to secure information system data, security breaches, or the direct or indirect effect on the companies' business resulting from the occurrence of cyber attacks, terrorist incidents or the threat of terrorist incidents, and acts of war;

• adoption of or changes in accounting policies, principles, or estimates, including the potential adoption of all or a portion of International Financial Accounting Standards; and

• new accounting or Securities and Exchange Commission or New York Stock Exchange requirements, or new interpretations of existing requirements.

Any forward-looking statement speaks only as of the date on which such statement is made. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. IDACORP and Idaho Power disclaim any obligation to update publicly any forward-looking information, whether in response to new information, future events, or otherwise, except as required by applicable law.

5

PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

IDACORP, Inc.

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(thousands of dollars except for per share amounts)
Operating Revenues:
Electric utility:
General business	$	306,066		$	252,313		$	724,025		$	649,881
Off-system sales	4,826			24,083			43,953			74,648
Other revenues	21,865			31,649			58,810			68,502
Total electric utility revenues	332,757			308,045			826,788			793,031
Other	1,262			1,585			3,074			3,076
Total operating revenues	334,019			309,630			829,862			796,107
Operating Expenses:
Electric utility:
Purchased power	71,570			66,141			151,026			127,658
Fuel expense	55,978			41,195			110,014			90,801
Power cost adjustment	(42,871		)	(10,189		)	(37,074		)	36,618
Other operations and maintenance	89,968			84,562			254,487			240,695
Energy efficiency programs	8,410			18,504			20,971			31,011
Depreciation	31,607			30,115			92,028			89,272
Taxes other than income taxes	7,012			7,302			22,961			21,696
Total electric utility expenses	221,674			237,630			614,413			637,751
Other	1,002			607			2,961			2,573
Total operating expenses	222,676			238,237			617,374			640,324
Operating Income	111,343			71,393			212,488			155,783
Other Income, Net	2,928			6,010			16,091			15,589
Earnings (losses) of Unconsolidated Equity-Method Investments	1,304			2,085			795			(3,657		)
Interest Expense:
Interest on long-term debt	19,670			19,499			59,252			59,850
Other interest, net of AFUDC	(269		)	(2,053		)	(5,209		)	(5,876		)
Total interest expense, net	19,401			17,446			54,043			53,974
Income Before Income Taxes	96,174			62,042			175,331			113,741
Income Tax Expense (Benefit)	3,910			(45,372		)	22,812			(44,137		)
Net Income	92,264			107,414			152,519			157,878
Adjustment for income attributable to noncontrolling interests	(195		)	(347		)	(220		)	(170		)
Net Income Attributable to IDACORP, Inc.	$	92,069		$	107,067		$	152,299		$	157,708
Weighted Average Common Shares Outstanding - Basic (000’s)	49,966			49,520			49,918			49,411
Weighted Average Common Shares Outstanding - Diluted (000’s)	50,080			49,622			49,990			49,499
Earnings Per Share of Common Stock:
Earnings Attributable to IDACORP, Inc. - Basic	$	1.84		$	2.16		$	3.05		$	3.19
Earnings Attributable to IDACORP, Inc. - Diluted	$	1.84		$	2.16		$	3.05		$	3.19
Dividends Declared Per Share of Common Stock	$	0.33		$	0.30		$	0.99		$	0.90

The accompanying notes are an integral part of these statements.

6

IDACORP, Inc.

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(thousands of dollars)
Net Income	$	92,264		$	107,414		$	152,519		$	157,878
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period,   net of tax of $438, ($1,259), $968, and ($900)	682			(1,961		)	1,507			(1,401		)
Unfunded pension liability adjustment, net of tax   of $170, $150, $511, and $450	265			234			796			701
Total Comprehensive Income	93,211			105,687			154,822			157,178
Comprehensive income attributable to noncontrolling interests	(195		)	(347		)	(220		)	(170		)
Comprehensive Income Attributable to IDACORP, Inc.	$	93,016		$	105,340		$	154,602		$	157,008

The accompanying notes are an integral part of these statements.

7

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2012			December 31, 2011
	(thousands of dollars)
Assets
Current Assets:
Cash and cash equivalents	$	20,234		$	27,813
Receivables:
Customer (net of allowance of $1,691 and $1,239, respectively)	80,154			66,296
Other (net of allowance of $168 and $196, respectively)	20,923			8,197
Income taxes receivable	242			421
Accrued unbilled revenues	49,872			46,441
Materials and supplies (at average cost)	48,540			46,490
Fuel stock (at average cost)	52,626			47,865
Prepayments	13,007			12,405
Deferred income taxes	45,833			16,159
Current regulatory assets	28,936			34,279
Other	5,628			4,606
Total current assets	365,995			310,972
Investments	190,692			199,931
Property, Plant and Equipment:
Utility plant in service	4,890,835			4,466,873
Accumulated provision for depreciation	(1,692,089		)	(1,677,609		)
Utility plant in service - net	3,198,746			2,789,264
Construction work in progress	283,053			591,475
Utility plant held for future use	7,101			6,974
Other property, net of accumulated depreciation	17,936			18,877
Property, plant and equipment - net	3,506,836			3,406,590
Other Assets:
American Falls and Milner water rights	18,170			20,015
Company-owned life insurance	22,893			24,060
Regulatory assets	1,049,105			953,068
Long-term receivables (net of allowance of $2,865 and $2,743, respectively)	5,621			5,621
Other	48,325			40,352
Total other assets	1,144,114			1,043,116
Total	$	5,207,637		$	4,960,609

The accompanying notes are an integral part of these statements.

8

IDACORP, Inc.

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2012			December 31, 2011
	(thousands of dollars)
Liabilities and Equity
Current Liabilities:
Current maturities of long-term debt	$	1,064		$	101,064
Notes payable	51,400			54,200
Accounts payable	93,414			100,432
Income taxes accrued	937			505
Interest accrued	23,901			21,797
Current regulatory liabilities	37,193			29,738
Other	60,355			60,511
Total current liabilities	268,264			368,247
Other Liabilities:
Deferred income taxes	877,209			772,047
Regulatory liabilities	348,206			332,057
Pension and other postretirement benefits	339,324			363,209
Other	63,824			75,805
Total other liabilities	1,628,563			1,543,118
Long-Term Debt	1,536,573			1,387,550
Commitments and Contingencies
Equity:
IDACORP, Inc. shareholders’ equity:
Common stock, no par value (shares authorized 120,000,000;      50,156,986 and 49,964,172 shares issued, respectively)	835,742			828,389
Retained earnings	943,575			840,916
Accumulated other comprehensive loss	(9,319		)	(11,622		)
Treasury stock (1,513 and 12,177 shares at cost, respectively)	(21		)	(29		)
Total IDACORP, Inc. shareholders’ equity	1,769,977			1,657,654
Noncontrolling interests	4,260			4,040
Total equity	1,774,237			1,661,694
Total	$	5,207,637		$	4,960,609
The accompanying notes are an integral part of these statements.

9

IDACORP, Inc.

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2012			2011
	(thousands of dollars)
Operating Activities:
Net income	$	152,519		$	157,878
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	95,904			92,646
Deferred income taxes and investment tax credits	19,824			(54,340		)
Changes in regulatory assets and liabilities	(24,618		)	55,044
Pension and postretirement benefit plan expense	28,689			17,279
Contributions to pension and postretirement benefit plans	(47,466		)	(20,194		)
(Earnings) losses of unconsolidated equity-method investments	(795		)	3,657
Distributions from unconsolidated equity-method investments	12,375			2,375
Allowance for equity funds used during construction	(18,989		)	(18,264		)
Other non-cash adjustments to net income, net	2,046			3,731
Change in:
Accounts receivable and prepayments	(16,099		)	(12,121		)
Accounts payable and other accrued liabilities	(1,440		)	(2,209		)
Taxes accrued/receivable	11,457			31,472
Other current assets	(10,242		)	(24,556		)
Other current liabilities	(6,501		)	1,375
Other assets	(7,202		)	4,595
Other liabilities	(7,980		)	(3,458		)
Net cash provided by operating activities	181,482			234,910
Investing Activities:
Additions to property, plant and equipment	(187,751		)	(266,991		)
Proceeds from the sale of emission allowances and RECs	2,706			5,163
Investments in affordable housing	(107		)	(955		)
Other	(137		)	2,435
Net cash used in investing activities	(185,289		)	(260,348		)
Financing Activities:
Issuance of long-term debt	150,000			—
Retirement of long-term debt	(101,064		)	(121,064		)
Dividends on common stock	(49,950		)	(44,808		)
Net change in short-term borrowings	(2,800		)	(15,400		)
Issuance of common stock	4,839			10,408
Acquisition of treasury stock	(2,062		)	(1,933		)
Other	(2,735		)	872
Net cash used in financing activities	(3,772		)	(171,925		)
Net decrease in cash and cash equivalents	(7,579		)	(197,363		)
Cash and cash equivalents at beginning of the period	27,813			228,677
Cash and cash equivalents at end of the period	$	20,234		$	31,314
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	1,178		$	(11,543	)
Interest (net of amount capitalized)	$	50,137		$	52,505
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,595		$	22,715

The accompanying notes are an integral part of these statements.

10

IDACORP, Inc.

Condensed Consolidated Statements of Equity

(unaudited)

	Nine months ended September 30,
	2012			2011
	(thousands of dollars)
Common Stock
Balance at beginning of period	$	828,389		$	807,842
Issued	4,839			10,408
Other	2,514			2,021
Balance at end of period	835,742			820,271
Retained Earnings
Balance at beginning of period	840,916			733,879
Net income attributable to IDACORP, Inc.	152,299			157,708
Common stock dividends ($0.99 and $0.90 per share)	(49,640		)	(44,714		)
Balance at end of period	943,575			846,873
Accumulated Other Comprehensive (Loss) Income
Balance at beginning of period	(11,622		)	(9,568		)
Unrealized gain (loss) on securities (net of tax)	1,507			(1,401		)
Unfunded pension liability adjustment (net of tax)	796			701
Balance at end of period	(9,319		)	(10,268		)
Treasury Stock
Balance at beginning of period	(29		)	(40		)
Issued	2,070			1,944
Acquired	(2,062		)	(1,933		)
Balance at end of period	(21		)	(29		)
Total IDACORP, Inc. shareholders’ equity at end of period	1,769,977			1,656,847
Noncontrolling Interests
Balance at beginning of period	4,040			3,871
Net income attributable to noncontrolling interests	220			170
Balance at end of period	4,260			4,041
Total equity at end of period	$	1,774,237		$	1,660,888

The accompanying notes are an integral part of these statements.

11

Idaho Power Company

Condensed Consolidated Statements of Income

(unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
	(thousands of dollars)
Operating Revenues:
General business	$	306,066		$	252,313		$	724,025		$	649,881
Off-system sales	4,826			24,083			43,953			74,648
Other revenues	21,865			31,649			58,810			68,502
Total operating revenues	332,757			308,045			826,788			793,031
Operating Expenses:
Operation:
Purchased power	71,570			66,141			151,026			127,658
Fuel expense	55,978			41,195			110,014			90,801
Power cost adjustment	(42,871		)	(10,189		)	(37,074		)	36,618
Other operations and maintenance	89,968			84,562			254,487			240,695
Energy efficiency programs	8,410			18,504			20,971			31,011
Depreciation	31,607			30,115			92,028			89,272
Taxes other than income taxes	7,012			7,302			22,961			21,696
Total operating expenses	221,674			237,630			614,413			637,751
Income from Operations	111,083			70,415			212,375			155,280
Other Income (Expense):
Allowance for equity funds used during construction	3,541			6,570			18,989			18,264
Earnings of unconsolidated equity-method investments	2,906			3,741			6,933			1,172
Other expense, net	(769		)	(293		)	(3,615		)	(2,669		)
Total other income	5,678			10,018			22,307			16,767
Interest Charges:
Interest on long-term debt	19,670			19,499			59,252			59,850
Other interest	1,617			1,026			4,756			3,551
Allowance for borrowed funds used during construction	(1,986		)	(3,188		)	(10,269		)	(9,777		)
Total interest charges	19,301			17,337			53,739			53,624
Income Before Income Taxes	97,460			63,096			180,943			118,423
Income Tax Expense (Benefit)	7,864			(41,776		)	30,818			(36,997		)
Net Income	$	89,596		$	104,872		$	150,125		$	155,420

The accompanying notes are an integral part of these statements.

12

Idaho Power Company

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three months ended September 30,					Nine months ended September 30,
	2012		2011			2012		2011
	(thousands of dollars)
Net Income	$	89,596	$	104,872		$	150,125	$	155,420
Other Comprehensive Income:
Net unrealized holding gains (losses) arising during the period,   net of tax of $438, ($1,259), $968, and ($900)	682		(1,961		)	1,507		(1,401		)
Unfunded pension liability adjustment, net of tax   of $170, $150, $511, and $450	265		234			796		701
Total Comprehensive Income	$	90,543	$	103,145		$	152,428	$	154,720

The accompanying notes are an integral part of these statements.

13

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2012			December 31, 2011
	(thousands of dollars)
Assets
Electric Plant:
In service (at original cost)	$	4,890,835		$	4,466,873
Accumulated provision for depreciation	(1,692,089		)	(1,677,609		)
In service - net	3,198,746			2,789,264
Construction work in progress	283,053			591,475
Held for future use	7,101			6,974
Electric plant - net	3,488,900			3,387,713
Investments and Other Property	125,466			128,674
Current Assets:
Cash and cash equivalents	13,604			19,316
Receivables:
Customer (net of allowance of $1,691 and $1,239, respectively)	80,154			66,296
Other (net of allowance of $168 and $196, respectively)	20,756			8,011
Income taxes receivable	20,612			4,644
Accrued unbilled revenues	49,872			46,441
Materials and supplies (at average cost)	48,540			46,490
Fuel stock (at average cost)	52,626			47,865
Prepayments	12,857			12,274
Deferred income taxes	34,180			14,099
Current regulatory assets	28,936			34,279
Other	5,628			4,606
Total current assets	367,765			304,321
Deferred Debits:
American Falls and Milner water rights	18,170			20,015
Company-owned life insurance	22,893			24,060
Regulatory assets	1,049,105			953,068
Other	47,085			38,988
Total deferred debits	1,137,253			1,036,131
Total	$	5,119,384		$	4,856,839

The accompanying notes are an integral part of these statements.

14

Idaho Power Company

Condensed Consolidated Balance Sheets

(unaudited)

	September 30, 2012			December 31, 2011
	(thousands of dollars)
Capitalization and Liabilities
Capitalization:
Common stock equity:
Common stock, $2.50 par value (50,000,000 shares      authorized; 39,150,812 shares outstanding)	$	97,877		$	97,877
Premium on capital stock	712,257			704,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	835,758			735,304
Accumulated other comprehensive loss	(9,319		)	(11,622		)
Total common stock equity	1,634,476			1,524,220
Long-term debt	1,536,573			1,387,550
Total capitalization	3,171,049			2,911,770
Current Liabilities:
Long-term debt due within one year	1,064			101,064
Accounts payable	92,950			99,716
Accounts payable to affiliates	1,434			1,512
Interest accrued	23,901			21,797
Current regulatory liabilities	37,193			29,738
Other	59,755			59,785
Total current liabilities	216,297			313,612
Deferred Credits:
Deferred income taxes	983,198			863,044
Regulatory liabilities	348,206			332,057
Pension and other postretirement benefits	339,324			363,209
Other	61,310			73,147
Total deferred credits	1,732,038			1,631,457
Commitments and Contingencies
Total	$	5,119,384		$	4,856,839
The accompanying notes are an integral part of these statements.

15

Idaho Power Company

Condensed Consolidated Statements of Capitalization

(unaudited)

	September 30, 2012			December 31, 2011
	(thousands of dollars)
Common Stock Equity:
Common stock	$	97,877		$	97,877
Premium on capital stock	712,257			704,758
Capital stock expense	(2,097		)	(2,097		)
Retained earnings	835,758			735,304
Accumulated other comprehensive loss	(9,319		)	(11,622		)
Total common stock equity	1,634,476			1,524,220
Long-Term Debt:
First mortgage bonds:
4.75% Series due 2012	—			100,000
4.25% Series due 2013	70,000			70,000
6.025% Series due 2018	120,000			120,000
6.15% Series due 2019	100,000			100,000
4.50% Series due 2020	130,000			130,000
3.40% Series due 2020	100,000			100,000
2.95% Series due 2022	75,000			—
6% Series due 2032	100,000			100,000
5.50% Series due 2033	70,000			70,000
5.50% Series due 2034	50,000			50,000
5.875% Series due 2034	55,000			55,000
5.30% Series due 2035	60,000			60,000
6.30% Series due 2037	140,000			140,000
6.25% Series due 2037	100,000			100,000
4.85% Series due 2040	100,000			100,000
4.30% Series due 2042	75,000			—
Total first mortgage bonds	1,345,000			1,295,000
Amount due within one year	—			(100,000		)
Net first mortgage bonds	1,345,000			1,195,000
Pollution control revenue bonds:
5.15% Series due 2024	49,800			49,800
5.25% Series due 2026	116,300			116,300
Variable Rate Series 2000 due 2027	4,360			4,360
Total pollution control revenue bonds	170,460			170,460
American Falls bond guarantee	19,885			19,885
Milner Dam note guarantee	5,318			6,382
Note guarantee due within one year	(1,064		)	(1,064		)
Unamortized premium/discount - net	(3,026		)	(3,113		)
Total long-term debt	1,536,573			1,387,550
Total Capitalization	$	3,171,049		$	2,911,770

The accompanying notes are an integral part of these statements.

16

Idaho Power Company

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Nine months ended September 30,
	2012			2011
	(thousands of dollars)
Operating Activities:
Net income	$	150,125		$	155,420
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	95,451			92,232
Deferred income taxes and investment tax credits	44,410			(56,078		)
Changes in regulatory assets and liabilities	(24,618		)	55,044
Pension and postretirement benefit plan expense	28,689			17,279
Contributions to pension and postretirement benefit plans	(47,466		)	(20,194		)
Earnings of unconsolidated equity-method investments	(6,933		)	(1,172		)
Distributions from unconsolidated equity-method investments	11,750			1,075
Allowance for equity funds used during construction	(18,989		)	(18,264		)
Other non-cash adjustments to net income, net	(510		)	1,383
Change in:
Accounts receivables and prepayments	(17,323		)	(12,213		)
Accounts payable	(1,208		)	(2,120		)
Taxes accrued/receivable	(5,170		)	35,496
Other current assets	(10,242		)	(24,556		)
Other current liabilities	(6,502		)	1,375
Other assets	(7,203		)	4,595
Other liabilities	(7,836		)	(2,702		)
Net cash provided by operating activities	176,425			226,600
Investing Activities:
Additions to utility plant	(187,751		)	(266,991		)
Proceeds from the sale of emission allowances and RECs	2,706			5,163
Other	(124		)	1,820
Net cash used in investing activities	(185,169		)	(260,008		)
Financing Activities:
Issuance of long-term debt	150,000			—
Retirement of long-term debt	(101,064		)	(121,064		)
Dividends on common stock	(49,671		)	(44,768		)
Capital contribution from parent	7,500			—
Other	(3,733		)	—
Net cash provided by (used in) financing activities	3,032			(165,832		)
Net decrease in cash and cash equivalents	(5,712		)	(199,240		)
Cash and cash equivalents at beginning of the period	19,316			224,233
Cash and cash equivalents at end of the period	$	13,604		$	24,993
Supplemental Disclosure of Cash Flow Information:
Cash paid (received) during the period for:
Income taxes	$	1,224		$	(6,689	)
Interest (net of amount capitalized)	$	49,833		$	52,148
Non-cash investing activities:
Additions to property, plant and equipment in accounts payable	$	22,595		$	22,715

The accompanying notes are an integral part of these statements.

17

IDACORP, INC. AND IDAHO POWER COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

This Quarterly Report on Form 10-Q is a combined report of IDACORP, Inc. (IDACORP) and Idaho Power Company (Idaho Power).  Therefore, these Notes to Condensed Consolidated Financial Statements apply to both IDACORP and Idaho Power.  However, Idaho Power makes no representation as to the information relating to IDACORP’s other operations.

Nature of Business

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power.  Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  Idaho Power's utility operations are regulated primarily by the Federal Energy Regulatory Commission (FERC) and the state regulatory commissions of Idaho and Oregon.  Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company (Ida-West), an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy (IE), a marketer of energy commodities, which wound down operations in 2003.

Principles of Consolidation

IDACORP’s and Idaho Power’s consolidated financial statements include the accounts of each company, the subsidiaries that the companies control, and any variable interest entities (VIEs) for which the companies are the primary beneficiaries.  Intercompany balances have been eliminated in consolidation.  Investments in subsidiaries that the companies do not control and investments in VIEs for which the companies are not the primary beneficiaries, but have the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method of accounting.

The entities that IDACORP and Idaho Power consolidate consist primarily of the wholly-owned subsidiaries discussed above.  In addition, IDACORP consolidates one VIE, Marysville Hydro Partners (Marysville), which is a joint venture owned 50 percent by Ida-West and 50 percent by Environmental Energy Company (EEC).  Marysville has approximately $21 million of assets, primarily a hydroelectric plant, and approximately $15 million of intercompany long-term debt, which is eliminated in consolidation.  EEC has borrowed amounts from Ida-West to fund a portion of its required capital contributions to Marysville.  The loans are payable from EEC’s share of distributions and are secured by the stock of EEC and EEC’s interest in Marysville.  Ida-West is the primary beneficiary because the ownership of the intercompany note and the EEC note result in it controlling the entity.  Creditors of Marysville have no recourse to the general credit of IDACORP and there are no other arrangements that could require IDACORP to provide financial support to Marysville or expose IDACORP to losses.

Through IERCo, Idaho Power holds a variable interest in BCC, a VIE for which it is not the primary beneficiary.  IERCo is not the primary beneficiary because the power to direct the activities that most significantly impact the economic performance of BCC is shared with the joint venture partner.  The carrying value of BCC was $97 million at September 30, 2012, and Idaho Power's maximum exposure to loss is the carrying value, plus any additional future contributions to BCC and a $63 million guarantee for mine reclamation costs, which is discussed further in Note 8.

Through IFS, IDACORP also holds variable interests in VIEs for which it is not the primary beneficiary.  These VIEs are affordable housing developments and other real estate investments in which IFS holds limited partnership interests ranging from 5 to 99 percent.  As a limited partner, IFS does not control these entities and they are not consolidated.  These investments were acquired between 1996 and 2010.  IFS’s maximum exposure to loss in these developments is limited to its net carrying value, which was $54 million at September 30, 2012.

Regulation of Utility Operations

IDACORP's and Idaho Power's financial statements reflect the effects of the different ratemaking principles followed by the jurisdictions regulating Idaho Power.  The application of accounting principles related to regulated operations sometimes results

18

in Idaho Power recording expenses and revenues in a different period than when an unregulated enterprise would otherwise record expenses and revenues.  In these instances, the amounts are deferred as regulatory assets or regulatory liabilities on the balance sheet and recorded on the income statement when recovered or returned in rates.  Additionally, regulators can impose regulatory liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers.  The effects of applying these regulatory accounting principles to Idaho Power's operations are discussed in more detail in Note 3.

Financial Statements

In the opinion of management of IDACORP and Idaho Power, the accompanying unaudited condensed consolidated financial statements contain all adjustments necessary to present fairly each company's consolidated financial position as of September 30, 2012, consolidated results of operations for the three and nine months endedSeptember 30, 2012 and 2011, and consolidated cash flows for the nine months endedSeptember 30, 2012 and 2011.  These adjustments are of a normal and recurring nature.  These financial statements do not contain the complete detail or footnote disclosure concerning accounting policies and other matters that would be included in full-year financial statements and should be read in conjunction with the audited consolidated financial statements included in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2011.  The results of operations for the interim period are not necessarily indicative of the results to be expected for the full year. A change in management's estimates or assumptions could have a material impact on IDACORP's or Idaho Power's respective financial condition and results of operations during the period in which such change occurred.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosures of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Actual results experienced could differ materially from those estimates.

2.  INCOME TAXES

In accordance with interim reporting requirements, IDACORP and Idaho Power use an estimated annual effective tax rate for computing their provisions for income taxes. An estimate of annual income tax expense (or benefit) is made each interim period using estimates for annual pre-tax income, income tax adjustments, and tax credits. The estimated annual effective tax rates do not include discrete events such as tax law changes, examination settlements, or method changes. Discrete events are recorded in the interim period in which they occur.

The estimated annual effective tax rate is applied to year-to-date pre-tax income to determine income tax expense (or benefit) for the interim period consistent with the annual estimate. In subsequent interim periods, income tax expense (or benefit) for the period is computed as the difference between the year-to-date amount reported for the previous interim period and the current period's year-to-date amount.

19

Income Tax Expense

The following table provides a summary of income tax expense (benefit) for the three and nine months endedSeptember 30 (in thousands of dollars):

	IDACORP						Idaho Power
	2012			2011			2012			2011
Three months ended September 30,
Income tax at statutory rates (federal and state)	$	37,528		$	24,123		$	38,107		$	24,671
Additional accumulated deferred investment tax credit (ADITC) amortization	—			6,750			—			6,750
Accounting method change	(7,845		)	—			(7,845		)	—
Examination settlement - uniform capitalization	—			(56,898		)	—			(56,898		)
Other (1)	(25,773		)	(19,347		)	(22,398		)	(16,299		)
Income tax expense (benefit)	$	3,910		$	(45,372	)	$	7,864		$	(41,776	)
Effective tax rate	4.1		%	(73.5		)%	8.1		%	(66.2		)%
Nine months ended September 30,
Income tax at statutory rates (federal and state)	$	68,468		$	44,407		$	70,749		$	46,303
Accounting method change	(7,845		)	—			(7,845		)	—
Examination settlement - capitalized repairs	—			(3,428		)	—			(3,428		)
Examination settlement - uniform capitalization	—			(56,898		)	—			(56,898		)
Other (1)	(37,811		)	(28,218		)	(32,086		)	(22,974		)
Income tax expense (benefit)	$	22,812		$	(44,137	)	$	30,818		$	(36,997	)
Effective tax rate	13.0		%	(38.9		)%	17.0		%	(31.2		)%

⁽¹⁾ "Other" is primarily comprised of Idaho Power's regulatory flow-through tax adjustments, which are listed in the rate reconciliation table of Note 2 to the consolidated financial statements included in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

The changes in year-to-date 2012 income tax expense as compared to the same period in 2011 were primarily due to U.S. Internal Revenue Service (IRS) examination settlements in 2011, greater Idaho Power pre-tax earnings in 2012, and a tax accounting method change at Idaho Power (discussed below). Net regulatory flow-through tax adjustments at Idaho Power were higher for the nine months endedSeptember 30, 2012 as compared to the same period in 2011, primarily due to the capitalized repairs deduction estimate.

Accounting Method Change: In the third quarter of 2012 Idaho Power completed an income tax accounting method change for its 2011 tax year related to the transmission and distribution portion of the capitalized repairs method it adopted in fiscal year 2010. The $7.8 million tax benefit is related to the filed deduction for the cumulative method change adjustment for years prior to 2011. The change was made pursuant to Revenue Procedure 2011-43 to bring Idaho Power's existing method into alignment with the Revenue Procedure's safe harbor unit-of-property definitions for electric transmission and distribution property. Following the automatic consent procedures provided for in the Revenue Procedure, Idaho Power adopted this method with the filing of IDACORP's 2011 consolidated federal income tax return. The IRS approved the method change prior to the filing of the return as part of IDACORP's 2011 Compliance Assurance Process examination.

In April 2011, IDACORP and the IRS reached an agreement on Idaho Power's 2009 tax accounting method change for capitalized repairs. Finalization of this matter resulted in Idaho Power recognizing $3.4 million of previously unrecognized tax benefits for the method in the second quarter of 2011. As discussed above, Idaho Power's current change to its capitalized repairs method was the result of new IRS guidance which further refined its existing repairs method as it relates to transmission and distribution property. The provisions of the Revenue Procedure were unrelated to Idaho Power's examination issues, and the guidance was published months after settlement was reached.

Idaho Power's prescribed regulatory accounting treatment requires immediate income recognition for temporary tax differences of this type.  A regulatory asset is established to reflect Idaho Power's ability to recover increased income tax expense when such temporary differences reverse. Idaho Power's 2012 capitalized repairs deduction estimate incorporates the provisions of this method change.

20

3.  REGULATORY MATTERS

Recent and Pending Idaho Regulatory Matters

Idaho General Rate Case Settlement

On June 1, 2011, Idaho Power filed a general rate case with the IPUC. On September 23, 2011, Idaho Power, the IPUC Staff, and other interested parties publicly filed a settlement stipulation with the IPUC resolving most of the key contested issues in the Idaho general rate case. On December 30, 2011, the IPUC issued an order approving the settlement stipulation. The settlement stipulation provides for a 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a $34.0 million overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues, effective January 1, 2012. While both are final, neither the order nor the settlement stipulation specified an authorized rate of return on equity.

Settlement Stipulation -- Investment Tax Credits and Idaho Sharing Mechanism

On January 13, 2010, the IPUC approved a rate settlement agreement among Idaho Power, several of Idaho Power's customers, the IPUC Staff, and other parties.  The settlement agreement provided for (a) the use of additional ADITC to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho ROE), and (b) an equal sharing between Idaho Power and its customers of Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE.  The sharing and ADITC amortization provisions of the January 2010 settlement agreement terminated on December 31, 2011.

On November 2, 2011, Idaho Power filed an application with the IPUC requesting an extension of the two elements of the January 2010 settlement agreement described above. On December 27, 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.0 percent and up to and including a 10.5 percent Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; and

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho-jurisdiction earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customers through an offset in the pension balancing account.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. The automatic adjustments would be as follows: (a) the 9.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 95 percent of the new authorized rate of return on equity; (b) the 10.0 percent Idaho ROE trigger in the settlement stipulation would be re-established at the new authorized rate of return on equity; and (c) the 10.5 percent Idaho ROE trigger in the settlement stipulation would be replaced by the percentage equal to 105 percent of the new authorized rate of return on equity.

Based on the terms of the 2011 settlement stipulation, Idaho Power recorded during the third quarter of 2012 a $6.3 million provision against current revenues, to be refunded to customers through a future rate reduction, and an additional $5.8 million of pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future.

Revenue-Sharing Order Under January 2010 and December 2011 Settlement Agreements

On March 2, 2012, Idaho Power filed an application with the IPUC requesting authority to share revenues with customers based on year-end 2011 financial results, in accordance with the terms of settlement agreements executed in January 2010 and December 2011 described above. Idaho Power's revenue-sharing arrangements had two components: (1) a power cost adjustment mechanism component, which reduced net rates by $27.1 million effective June 1, 2012, and (2) a pension

21

balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction as a regulatory liability, and the $20.3 million pension regulatory asset reduction, in 2011. On May 31, 2012, the IPUC approved Idaho Power's March 2, 2012 application requesting a corresponding adjustment to Idaho-jurisdiction rates, effective for the period from June 1, 2012 to May 31, 2013.

Annual Power Cost Adjustment Mechanism Filing

Idaho Power has power cost adjustment (PCA) mechanisms in its Idaho and Oregon jurisdictions that address the volatility of power supply costs and provide for annual adjustments to the rates charged to retail customers. In the Idaho jurisdiction, the annual PCA adjustments are based on (a) a forecast component, based on a forecast of net power supply costs in the coming year as compared to net power supply costs in base rates, and (b) a true-up component, based on the difference between the previous year’s actual net power supply costs and the previous year’s forecast.  The latter component also includes a balancing mechanism so that, over time, the actual collection or refund of authorized true-up dollars matches the amounts authorized.  On May 31, 2012, the IPUC issued an order approving Idaho Power's April 13, 2012 application requesting a $43.0 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The PCA rate increase was offset by $27.1 million to be shared with customers pursuant to the revenue sharing order described above, resulting in a net rate increase of $15.9 million for these orders. By comparison, the PCA rates in effect from June 1, 2011 to May 31, 2012 were based on a May 31, 2011 IPUC order approving Idaho Power's requested $40.4 million Idaho PCA rate decrease.

Fixed Cost Adjustment Filings

The fixed cost adjustment (FCA) began as a pilot program for Idaho Power’s Idaho residential and small general service customers, running from 2007 through 2009.  The FCA is designed to remove Idaho Power’s disincentive to invest in energy efficiency programs by separating (or decoupling) the recovery of fixed costs from the variable kilowatt-hour charge and linking it instead to a set amount per customer.  The FCA is adjusted each year to collect, or refund, the difference between the allowed fixed-cost recovery amount and the actual fixed costs recovered by Idaho Power during the year.

On April 29, 2010, the IPUC approved a two-year extension of the FCA pilot program, retroactively effective from January 1, 2010 through December 31, 2011. On March 30, 2012, the IPUC issued an order approving the FCA as a permanent program. The order also maintained the existing cap on the FCA of no more than three percent of base revenue, with any excess deferred for collection in a subsequent year. The IPUC noted in its order, however, that the FCA does not isolate or identify changes in cost recovery associated solely with Idaho Power's energy efficiency programs, and instead responds to all changes in load. While the IPUC rejected the IPUC Staff's proposal that FCA results be shared 50 percent with customers, the IPUC's order directed Idaho Power to file with the IPUC a proposal to adjust the FCA to address specified factors. On September 28, 2012, Idaho Power submitted a compliance filing and motion to the IPUC requesting that the IPUC approve the FCA methodology used during the pilot program, without change, or an alternative methodology proposed by Idaho Power. The alternative would maintain the existing three percent cap on the FCA, while introducing an additional symmetrical cap based on the annual change in energy consumption per customer of plus or minus two percent from the historical average. Proceedings relating to a potential change to the FCA are ongoing.

On May 8, 2012, the IPUC issued an order authorizing Idaho Power to increase its annual FCA collection to $10.3 million, a $1.2 million increase in FCA rates, for the period from June 1, 2012 to May 31, 2013.

Langley Gulch Power Plant Cost Recovery Filing - Idaho

On September 1, 2009, Idaho Power received pre-approval from the IPUC to include $396.6 million of construction costs in Idaho Power’s rate base when the Langley Gulch natural gas-fired power plant achieved commercial operation. On March 2, 2012, Idaho Power filed an application with the IPUC requesting an increase in annual Idaho-jurisdiction base rates of $59.9 million for recovery of Idaho Power's investment and associated costs for the Langley Gulch power plant. Idaho Power's application stated that its estimated investment in the plant through June 2012 was approximately $398 million. After the impact of depreciation, deferred income taxes, amounts currently included in rates, and an Idaho-jurisdictional cost allocation, Idaho Power's application requested a $336.7 million increase in Idaho-jurisdiction rate base. Idaho Power's requested base rate increase was based on an overall rate of return of 7.86 percent, as authorized by a prior IPUC order. On May 30, 2012, the IPUC Staff recommended to the IPUC that the $59.9 million increase in annual Idaho-jurisdiction base rates requested by Idaho Power be reduced to $58.1 million. The plant became commercially available on June 29, 2012. On that date, the IPUC issued an order consistent with the IPUC Staff's recommendation, approving a $58.1 million increase in annual Idaho- jurisdiction base rates, effective July 1, 2012. The order also provided for a $335.9 million increase in Idaho rate base.

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Inclusion of the Langley Gulch power plant in Idaho Power's power supply portfolio resulted in a change in Idaho Power's power supply cost assumptions. Accordingly, in the Langley Gulch order the IPUC updated Idaho Power's load-change adjustment rate (LCAR) to $17.64 per MWh, effective July 1, 2012. The LCAR is intended to eliminate recovery of power supply expenses already collected in rates associated with load changes resulting from changing weather conditions, a growing customer base, or changing customer use patterns. The LCAR adjusts power supply cost recovery within the Idaho jurisdiction PCA formula upwards or downwards for differences between actual load and the load used in calculating base rates. The settlement stipulation that became effective January 1, 2012 provided for a LCAR of $18.16 per MWh, compared to the rate of $19.67 per MWh in effect prior to that date.

Energy Efficiency and Demand Response Programs

Idaho Power manages a wide range of opportunities for its customers to participate in energy efficiency and demand response programs.  On March 15, 2012, Idaho Power filed an application with the IPUC requesting an order designating Idaho Power's 2011 demand-side management expenditures of $42.6 million as prudently incurred. On October 22, 2012, the IPUC issued an order approving as prudently incurred $41.9 million of demand-side management expenditures, and deferred a portion of Idaho Power's additional requested amount for further review. Of Idaho Power's 2011 demand-side management expenditures, approximately $36 million were funded through a rider mechanism on customer bills and approximately $7 million were recorded as a regulatory asset. As of September 30, 2012, the Idaho portion of the energy efficiency rider balance was a regulatory liability of $2.5 million. Idaho Power's previous application filed in March 2011, which was approved by the IPUC in August 2011, designated Idaho Power's 2010 Idaho energy efficiency rider expenditures of approximately $42 million as prudently incurred expenses.

Typically, a majority of energy efficiency activities are funded through a rider mechanism on customer bills. Program expenditures are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no impact on earnings. The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers. In the 2012 PCA filing, funding for certain demand response program costs was shifted from the rider mechanism to the PCA mechanism as these costs are closely related to and directly impact the other power supply costs collected through the PCA.

Cost Recovery for Cessation of Boardman Coal-Fired Operations - Idaho

In December 2010, the Oregon Environmental Quality Commission approved a plan to cease coal-fired operations at the Boardman power plant not later than December 31, 2020. The plan results in increased revenue requirements for Idaho Power related to accelerated depreciation expense, additional plant investments, and decommissioning costs. In response to an application filed by Idaho Power, on February 15, 2012 the IPUC issued an order accepting Idaho Power's regulatory accounting and cost recovery plan associated with the early plant shut-down and approving the establishment of a balancing account whereby incremental costs and benefits associated with the early shut-down will be tracked for recovery in a subsequent proceeding. On February 15, 2012, Idaho Power filed an application with the IPUC requesting a $1.6 million annual increase in Idaho-jurisdiction base rates to recover the incremental Idaho-jurisdiction levelized annual revenue deficiency associated with early shut-down. On May 17, 2012, the IPUC issued an order approving a $1.5 million annual increase in Idaho-jurisdiction base rates, with new rates effective June 1, 2012. As of September 30, 2012, Idaho Power's net book value in the Boardman plant was $21.4 million.

Idaho Depreciation Rate Filings

Idaho Power's advanced metering infrastructure (AMI) project provides the means to automatically retrieve and store energy consumption information, eliminating manual meter reading expense. Commencing June 1, 2009, the IPUC approved a rate increase, allowing Idaho Power to recover the three-year accelerated depreciation of the existing non-AMI metering equipment and to begin earning a return on its AMI investment.  On April 27, 2012, the IPUC approved Idaho Power's February 15, 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

In connection with a depreciation study authorized by Idaho Power and conducted by a third party, on February 15, 2012, Idaho Power filed an application with the IPUC seeking to institute revised depreciation rates for electric plant-in-service, based upon updated service life estimates and net salvage percentages for all plant assets, and adjust Idaho-jurisdiction base rates to reflect the revised depreciation rates. Idaho Power's application requested a $2.7 million increase in Idaho-jurisdiction base rates. On May 31, 2012, the IPUC issued an order approving a settlement stipulation agreed to by Idaho Power, the IPUC Staff, and a

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large industrial customer of Idaho Power, which provided for a $1.3 million annual decrease in Idaho-jurisdiction base rates, effective June 1, 2012.

Recent and Pending Oregon Regulatory Matters

Oregon General Rate Case Filing

On July 29, 2011, Idaho Power filed a general rate case and proposed rate schedules with the OPUC, Case No. UE 233. The filing requested a $5.8 million increase in annual Oregon jurisdiction revenues and an authorized rate of return on equity of 10.5 percent, with an Oregon retail rate base of approximately $121.9 million. Idaho Power, the OPUC Staff, and other interested parties executed and filed a partial settlement stipulation with the OPUC on February 1, 2012, resolving all matters in the general rate case other than the prudence of costs associated with pollution control investments at the Jim Bridger coal-fired power plant. The settlement stipulation provided for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.76 percent in the Oregon jurisdiction. On February 23, 2012, the OPUC issued an order adopting the settlement stipulation. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC is conducting a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger plant.

Langley Gulch Power Plant Cost Recovery Filing - Oregon

On March 9, 2012, Idaho Power filed an application with the OPUC requesting an annual increase in Oregon jurisdiction revenues of $3.0 million for inclusion of the Langley Gulch power plant in Idaho Power's rate base. On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates effective October 1, 2012.

Federal Open Access Transmission Tariff Rate

Idaho Power uses a formula rate for transmission service provided under its open access transmission tariff (OATT), which allows transmission rates to be updated annually based on financial and operational data Idaho Power files with the FERC. On June 1, 2012, Idaho Power posted its 2012 transmission rate draft informational filing reflecting an OATT rate of $21.32 per kW-year, to be effective for the period from October 1, 2012 to September 30, 2013. On August 27, 2012, Idaho Power made its final informational filing with the FERC with the same OATT rate. Idaho Power's filing was based on its net annual transmission revenue requirement of $108.4 million. The OATT rate in effect from October 1, 2011 to September 30, 2012 was $19.79 per kW-year, based on a net annual transmission revenue requirement of $106.6 million.

4.  LONG-TERM DEBT

As of September 30, 2012, IDACORP had approximately $539 million remaining on a shelf registration statement filed with the U.S. Securities and Exchange Commission (SEC) that can be used for the issuance of debt securities or IDACORP common stock.

In May 2010, Idaho Power registered with the SEC up to $500 million of first mortgage bonds and debt securities.  On June 17, 2010, Idaho Power entered into a selling agency agreement with ten banks named in the agreement in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds.  In August 2010, Idaho Power issued $100 million of 3.40% first mortgage bonds, medium-term notes, Series I, maturing in August 2020, and $100 million of 4.85% first mortgage bonds, medium-term notes, Series I, maturing in August 2040. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022, and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042. The first mortgage bonds were issued under Idaho Power's shelf registration statement. As a result of these issuances, as of September 30, 2012, $150 million remained on Idaho Power’s shelf registration for the issuance of first mortgage bonds and debt securities.

In May 2012, Idaho Power used a portion of the net proceeds of the April 2012 sale of first mortgage bonds, medium-term notes to effect the early redemption in full of its $100 million of 4.75% first mortgage bonds, medium-term notes due November 2012.

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5.  NOTES PAYABLE

Credit Facilities

IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively, which may be used for general corporate purposes and commercial paper backup. IDACORP's credit facility consists of a revolving line of credit not to exceed the aggregate principal amount at any one time outstanding of $125 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $15 million, and letters of credit in an aggregate principal amount at any time outstanding not to exceed $50 million. Idaho Power's credit facility consists of a revolving line of credit, through the issuance of loans and standby letters of credit, not to exceed the aggregate principal amount at any one time outstanding of $300 million, including swingline loans in an aggregate principal amount at any time outstanding not to exceed $30 million. IDACORP and Idaho Power have the right to request an increase in the aggregate principal amount of the facilities to $150 million and $450 million, respectively, in each case subject to certain conditions.

The IDACORP and Idaho Power credit agreements have similar terms and conditions. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. Under their respective facilities, the companies pay a facility fee on the commitment based on the respective company's credit rating for senior unsecured long-term debt securities. While the credit facilities provide for an original maturity date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On October 12, 2012, IDACORP and Idaho Power executed First Extension Agreements with each ofthe lenders, extending the maturity dates under both agreements to October 26, 2017.

At September 30, 2012, no loans were outstanding under either IDACORP's or Idaho Power's facilities.  At September 30, 2012, Idaho Power had regulatory authority to incur up to $450 million principal amount of short-term indebtedness at any one time outstanding. Balances (in thousands of dollars) and interest rates of IDACORP’s and Idaho Power's short-term borrowings were as follows at September 30, 2012 and December 31, 2011:

	September 30, 2012									December 31, 2011
	Idaho Power			IDACORP			Total			Idaho Power			IDACORP			Total
Commercial paper outstanding	$	—		$	51,400		$	51,400		$	—		$	54,200		$	54,200
Weighted-average annual interest rate	—		%	0.47		%	0.47		%	—		%	0.47		%	0.47		%

6.  COMMON STOCK

IDACORP Common Stock

During the nine months endedSeptember 30, 2012, IDACORP issued an aggregate of 192,814 shares of common stock pursuant to its IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan, Idaho Power Company Employee Savings Plan, IDACORP, Inc. Restricted Stock Plan, and IDACORP, Inc. 2000 Long-Term Incentive and Compensation Plan. Effective July 1, 2012, IDACORP instructed the plan administrators of the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and Idaho Power Company Employee Savings Plan to use market purchases of IDACORP common stock, as opposed to original issuance of common stock from IDACORP, to acquire shares of IDACORP common stock for the plans. However, IDACORP may determine at any time to resume original issuances of common stock under those plans.

IDACORP enters into sales agency agreements as a means of selling its common stock from time to time pursuant to a continuous equity program.  IDACORP's current sales agency agreement is with BNY Mellon Capital Markets, LLC. As of September 30, 2012, there were approximately 3 million shares remaining available to be sold under the current sales agency agreement. No shares were issued under the sales agency agreement during the nine months endedSeptember 30, 2012.

Restrictions on Dividends

A covenant in each of IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65

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percent at the end of each fiscal quarter. Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants in their respective credit facilities or Idaho Power’s Revised Code of Conduct.  At September 30, 2012, the leverage ratios for IDACORP and Idaho Power were 47 percent and 49 percent, respectively.  Based on these restrictions, IDACORP’s and Idaho Power’s dividends were limited to $913 million and $806 million, respectively, at September 30, 2012.  There are additional facility covenants, subject to exceptions, that prohibit or restrict specified investments or acquisitions, mergers, or the sale or disposition of property without consent; the creation of specified forms of liens; and any agreements restricting dividend payments to the company from any material subsidiary.  At September 30, 2012, IDACORP and Idaho Power were in compliance with all facility covenants.

Idaho Power’s Revised Code of Conduct, approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval. At September 30, 2012, Idaho Power's common equity capital was 52 percent of its total adjusted capital. Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears.  Idaho Power has no preferred stock outstanding.

In addition to contractual restrictions on the amount and payment of dividends, the Federal Power Act prohibits the payment of dividends from "capital accounts." The term "capital accounts" is undefined in the Federal Power Act but could be interpreted to limit the payment of dividends by Idaho Power to the amount of Idaho Power's retained earnings.

7.  EARNINGS PER SHARE

The table below presents the computation of IDACORP’s basic and diluted earnings per share (EPS) for the three and nine months endedSeptember 30, 2012 and 2011 (in thousands, except for per share amounts).

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Numerator:
Net income attributable to IDACORP, Inc.	$	92,069	$	107,067	$	152,299	$	157,708
Denominator:
Weighted-average common shares outstanding - basic	49,966		49,520		49,918		49,411
Effect of dilutive securities:
Options	4		12		5		15
Restricted Stock	110		90		67		73
Weighted-average common shares outstanding - diluted	50,080		49,622		49,990		49,499
Basic earnings per share	$	1.84	$	2.16	$	3.05	$	3.19
Diluted earnings per share	$	1.84	$	2.16	$	3.05	$	3.19

The diluted EPS computations for the three and nine months endedSeptember 30, 2011 exclude 134,772 and 183,840 options, respectively, because the options’ exercise prices were greater than the average market price of the common stock during the periods.  In total, 16,706 options were outstanding at September 30, 2012, with expiration dates between 2013 and 2015.

8.  COMMITMENTS

Purchase Obligations

IDACORP's and Idaho Power's contractual obligations, outside of the ordinary course of business, have not changed materially from the amounts disclosed in their Annual Report on Form 10-K for the year ended December 31, 2011, except as follows:

• nine power purchase agreements were terminated due to either an uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties, which reduced Idaho Power's contractual payment obligations by approximately $736 million over the 15-year to 25-year lives of the contracts; and

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• Idaho Power issued $150 million of first mortgage bonds, medium-term notes (long-term indebtedness), using a portion of the net proceeds from that issuance to redeem prior to maturity $100 million of outstanding first mortgage bonds, medium-term notes due November 2012.

Guarantees

Idaho Power has agreed to guarantee a portion of the performance of reclamation activities and obligations at BCC, of which IERCo owns a one-third interest.  This guarantee, which is renewed each December, was $63 million at September 30, 2012, representing IERCo's one-third share of BCC's total reclamation obligation.  BCC has a reclamation trust fund set aside specifically for the purpose of paying these reclamation costs.  At September 30, 2012, the value of the reclamation trust fund was $77 million. During the three and nine months endedSeptember 30, 2012, the reclamation trust fund distributed approximately $8 million for reclamation activity costs associated with the BCC surface mine. BCC periodically assesses the adequacy of the reclamation trust fund and its estimate of future reclamation costs.  To ensure that the reclamation trust fund maintains adequate reserves, BCC has the ability to add a per-ton surcharge to coal sales, all of which are made to the Jim Bridger plant.  Starting in 2010, BCC began applying a nominal surcharge to coal sales in order to maintain adequate reserves in the reclamation trust fund.  Because of the existence of the fund and the ability to apply a per-ton surcharge, the estimated fair value of this guarantee is minimal.

IDACORP and Idaho Power enter into financial agreements and power purchase and sale agreements that include indemnification provisions relating to various forms of claims or liabilities that may arise from the transactions contemplated by these agreements.  Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated.  IDACORP and Idaho Power periodically evaluate the likelihood of incurring costs under such indemnities based on their historical experience and the evaluation of the specific indemnities.  As of September 30, 2012, management believes the likelihood is remote that IDACORP or Idaho Power would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnification obligations.  Neither IDACORP nor Idaho Power has recorded any liability on their respective condensed consolidated balance sheets with respect to these indemnification obligations.

9.  CONTINGENCIES

IDACORP and Idaho Power have in the past and expect in the future to become involved in various claims, controversies, disputes, and other contingent matters, including the items described in this Note 9.  Some of these claims, controversies, disputes, and other contingent matters involve litigation and regulatory or other contested proceedings.  IDACORP and Idaho Power intend to vigorously protect and defend their interests and pursue their rights.  However, the ultimate resolution and outcome of litigation and regulatory proceedings is inherently difficult to determine, particularly where (a) the remedies or penalties sought are indeterminate, (b) the proceedings are in the early stages or the substantive issues have not been well developed, or (c) the matters involve complex or novel legal theories or a large number of parties. In accordance with applicable accounting guidance, IDACORP and Idaho Power, as applicable, establish an accrual for legal proceedings when those matters proceed to a stage where they present loss contingencies that are both probable and reasonably estimable. In such cases, there may be a possible exposure to loss in excess of any amounts accrued. IDACORP and Idaho Power monitor those matters for developments that could affect the likelihood of a loss and the accrued amount, if any, thereof, and adjust the amount as appropriate. If the loss contingency at issue is not both probable and reasonably estimable, IDACORP and Idaho Power do not establish an accrual and the matter will continue to be monitored for any developments that would make the loss contingency both probable and reasonably estimable. As of the date of this report, IDACORP's and Idaho Power's accruals for loss contingencies are not material to their financial statements as a whole; however, future accruals could be material in a given period. IDACORP's and Idaho Power's determination is based on currently available information, and estimates presented in financial statements and other financial disclosures involve significant judgment and may be subject to significant uncertainty. As available information changes, the matters for which IDACORP and Idaho Power are able to estimate the loss may change, and the estimates themselves may change.

For certain of those matters described in this report for which IDACORP or Idaho Power have determined a loss contingency may, in the future, be at least reasonably possible, IDACORP and Idaho Power have stated that they are unable to estimate the possible loss or a range of possible loss that may result from those matters. Depending on a range of factors, such as the complexity of the facts, the unique nature of the legal theories, the pace of discovery, the timing of decisions of the court or arbiter, and the adverse party's willingness to negotiate towards a resolution, it may be months or years after the filing of a case or commencement of a proceeding before IDACORP or Idaho Power may be in a position to estimate the possible loss or range of possible loss for those matters. For matters that affect Idaho Power’s operations,

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Idaho Power intends to seek, to the extent permissible and appropriate, recovery of incurred costs through the ratemaking process.

Pacific Northwest Refund Proceedings

On July 25, 2001, the FERC issued an order establishing a proceeding to determine whether there may have been unjust and unreasonable charges for spot market sales in the Pacific Northwest during the period December 25, 2000 through June 20, 2001, because the spot market in the Pacific Northwest was affected by the dysfunction in the California market.  During that period, Idaho Power or IE both sold and purchased electricity in the Pacific Northwest. In 2003, the FERC terminated the proceeding and declined to order refunds, but in 2007 the Ninth Circuit issued an opinion, in Port of Seattle, Washington v. FERC, remanding to the FERC the orders that declined to require refunds.  The Ninth Circuit's opinion instructed the FERC to consider whether evidence of market manipulation would have altered the agency's conclusions about refunds and directed the FERC to include sales originating in the Pacific Northwest to the California Department of Water Resources (CDWR) in the scope of the proceeding.  The Ninth Circuit officially returned the case to the FERC on April 16, 2009. 

On October 3, 2011, the FERC issued its order on remand. The FERC ordered that the record be re-opened to permit parties seeking refunds to submit seller-specific evidence in support of their claims for sales made during the period confined to December 25, 2000 through June 20, 2001. The seller-specific claims must show that a seller engaged in unlawful market activity with a causal connection to have directly affected the negotiation of the specific contract or contracts to which the seller was a party. IE and Idaho Power understand the order to provide that neither claims of general dysfunction in the California markets nor in the Pacific Northwest market will be sufficient to support claims. While directing a trial-type hearing, the FERC also directed that the hearings be held in abeyance so that the matter may be presented to a settlement judge. In an order issued on November 23, 2011, the FERC's Chief Administrative Law Judge memorialized certain settlement procedures. IE and Idaho Power had reached a settlement with the California Parties in 2006 that disposed of their claims in the Pacific Northwest refund proceeding, as well as in California refund cases.

During the first three quarters of 2012, Idaho Power and each of the only two known direct claimants in the Pacific Northwest refund proceedings negotiated and entered into settlement agreements. The FERC approved the first settlement subject to conditions, which Idaho Power and IE have requested be removed on rehearing. Idaho Power and IE do not know when or how the FERC will rule on that request. The FERC approved the second settlement without conditions on October 19, 2012. The aggregate amount of the settlements was not material to the companies' financial statements. By the time established for the filing of testimony in the proceedings no other party presented any direct claims against Idaho Power or IE. While disposing of direct claims from both known claimants, the settlements and associated FERC orders did not eliminate the potential for so-called "ripple claims," which involve potential claims for refunds from an upstream seller of power based on a finding that its downstream buyer was liable for refunds as a seller of power during the relevant period. However, in its order approving one of Idaho Power's settlements, the FERC characterized the potential for such claims as "speculative." Based on its settlement of all known direct claims and the FERC's assessment of the potential for ripple claims as speculative, Idaho Power and IE have no remaining amount accrued for financial statement purposes relating to the Pacific Northwest refund proceedings. However, to the extent the availability of any ripple claims materializes, Idaho Power and IE will continue to vigorously defend their positions in the proceedings.

Water Rights - Snake River Basin Adjudication

Idaho Power holds water rights, acquired under applicable state law, for its hydroelectric projects.  In addition, Idaho Power holds water rights for domestic, irrigation, commercial, and other necessary purposes related to project lands and other holdings within the states of Idaho and Oregon.  Idaho Power's water rights for power generation are, to varying degrees, subordinated to future upstream appropriations for irrigation and other authorized consumptive uses.

Over time, increased irrigation development and other consumptive uses within the Snake River watershed led to a reduction in flows of the Snake River.  In the late 1970s and early 1980s these reduced flows resulted in a conflict between the exercise of Idaho Power's water rights at certain hydroelectric projects on the Snake River and upstream consumptive diversions.  The Swan Falls Agreement, signed by Idaho Power and the State of Idaho on October 25, 1984, resolved the conflict and provided a level of protection for Idaho Power's hydropower water rights at specified projects on the Snake River through the establishment of minimum stream flows and an administrative process governing future development of water rights that may affect those minimum stream flows.  In 1987, Congress enacted legislation directing the FERC to issue an order approving the Swan Falls settlement together with a finding that the agreement was neither inconsistent with the terms and conditions of Idaho Power's project licenses nor the Federal Power Act.  The FERC entered an order implementing the legislation in March 1988.

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The Swan Falls Agreement provided that the resolution and recognition of Idaho Power's water rights together with the State Water Plan provided a sound comprehensive plan for management of the Snake River watershed.  The Swan Falls Agreement also recognized, however, that in order to effectively manage the waters of the Snake River basin, a general adjudication to determine the nature, extent, and priority of the rights of all water uses in the basin was necessary.  Consistent with that recognition, in 1987 the State of Idaho initiated the Snake River Basin Adjudication (SRBA), and pursuant to the commencement order issued by the SRBA court that same year, all claimants to water rights within the basin were required to file water rights claims in the SRBA.  Idaho Power has filed claims to its water rights and has been actively participating in the SRBA since its commencement.  Questions concerning the effect of the Swan Falls Agreement on Idaho Power's water rights claims, including the nature and extent of the subordination of Idaho Power's rights to upstream uses, resulted in the filing of litigation in the SRBA in 2007 between Idaho Power and the State of Idaho.  This litigation was resolved by the Framework Reaffirming the Swan Falls Settlement (Framework) signed by Idaho Power and the State of Idaho on March 25, 2009.  In that Framework, the parties acknowledged that the effective management of Idaho's water resources remains critical to the public interest of the State of Idaho by sustaining economic growth, maintaining reasonable electric rates, protecting and preserving existing water rights, and protecting water quality and environmental values.  The Framework further provided that the State of Idaho and Idaho Power would cooperate in exploring approaches to resolve issues of mutual concern relating to the management of Idaho's water resources.  Idaho Power continues to work with the State of Idaho and other interested parties on these issues.

One such issue involves the management of the Eastern Snake Plain Aquifer (ESPA), a large underground aquifer in southeastern Idaho that is hydrologically connected to the Snake River.  House Concurrent Resolution No. 28, adopted by the Idaho Legislature in 2007, directed the Idaho Water Resource Board to pursue the development of a comprehensive management plan for the ESPA, to include measures that would enhance aquifer levels, springs, and river flows on the eastern Snake River plain to the benefit of both agricultural development and hydropower generation.  In May of 2007, the Idaho Water Resource Board appointed an advisory committee, charged with the responsibility of developing a management plan for the ESPA.  Idaho Power was a member of that committee.  In January 2009, the Idaho Water Resource Board, based on the committee's recommendations, adopted a Comprehensive Aquifer Management Plan (CAMP) for the ESPA.  The Idaho Legislature approved the CAMP that same year.  Idaho Power is a member of the CAMP Implementation Committee and continues to work with the Idaho Water Resource Board, other stakeholders, and the Idaho Legislature in exploring opportunities for implementation of the CAMP management plan.

Idaho Power also continues its active participation in the SRBA in seeking to ensure that its water rights are protected and that the operation of its hydroelectric projects is not adversely impacted.  While Idaho Power cannot predict the outcome, Idaho Power does not anticipate any material modification of its water rights as a result of the SRBA process.

Other Proceedings

IDACORP and Idaho Power are parties to legal claims and legal and regulatory actions and proceedings in the ordinary course of business that are in addition to those discussed above and, as noted above, records an accrual for associated loss contingencies when they are probable and reasonably estimable.  However, as of the date of this report the companies believe that resolution of those matters will not have a material adverse effect on their consolidated financial statements. Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of these regulations but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

10.  BENEFIT PLANS

Idaho Power has a noncontributory defined benefit pension plan covering most employees.  The benefits under the plan are based on years of service and the employee’s final average earnings.  In addition, Idaho Power has a nonqualified defined benefit plan for certain senior management employees called the Senior Management Security Plan (SMSP).  Idaho Power also maintains a defined benefit postretirement plan (consisting of health care and death benefits) that is available to all employees who were enrolled in the active group plan at the time of retirement as well as their spouses and qualifying dependents.  Idaho Power also has an Employee Savings Plan that complies with Section 401(k) of the Internal Revenue Code and covers substantially all employees.  Idaho Power matches specified percentages of employee contributions to the Employee Savings Plan.

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The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the three months ended September 30 (in thousands of dollars). 

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2012			2011			2012		2011		2012			2011
Service cost	$	6,392		$	5,120		$	537	$	487	$	323		$	330
Interest cost	7,872			7,581			805		773		784			859
Expected return on plan assets	(7,934		)	(7,968		)	—		—		(559		)	(660		)
Amortization of transition obligation	—			—			—		—		510			510
Amortization of prior service cost	87			130			53		61		(105		)	(105		)
Amortization of net loss	3,529			2,168			382		323		96			144
Net periodic benefit cost	9,946			7,031			1,777		1,644		1,049			1,078
Pension expense recognized under sharing mechanism (1)	5,800			—			—		—		—			—
Costs not recognized due to the effects of regulation (1)	(5,087		)	(2,371		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	10,659		$	4,660		$	1,777	$	1,644	$	1,049		$	1,078

⁽¹⁾  Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates. See Note 3 for information on Idaho Power's revenue sharing mechanism approved by the IPUC, which resulted in additional Idaho pension expense of $5.8 million for the three months ended September 30, 2012. 

The table below shows the components of net periodic benefit costs for the pension, SMSP, and postretirement benefits plans for the nine months endedSeptember 30 (in thousands of dollars).

	Pension Plan						Senior Management Security Plan				Postretirement Benefits
	2012			2011			2012		2011		2012			2011
Service cost	$	19,178		$	15,359		$	1,613	$	1,463	$	969		$	992
Interest cost	23,617			22,742			2,414		2,319		2,351			2,576
Expected return on plan assets	(23,801		)	(23,903		)	—		—		(1,676		)	(1,981		)
Amortization of transition obligation	—			—			—		—		1,530			1,530
Amortization of prior service cost	260			389			160		183		(316		)	(316		)
Amortization of net loss	10,586			6,505			1,146		969		288			433
Net periodic benefit cost	29,840			21,092			5,333		4,934		3,146			3,234
Pension expense recognized under sharing mechanism (1)	5,800			—			—		—		—			—
Costs not recognized due to the effects of regulation (1)	(15,430		)	(11,981		)	—		—		—			—
Net periodic benefit cost recognized for financial reporting (1)	$	20,210		$	9,111		$	5,333	$	4,934	$	3,146		$	3,234

⁽¹⁾  Net periodic benefit costs for the pension plan are recognized for financial reporting based upon the authorization of each regulatory jurisdiction in which Idaho Power operates. Under IPUC order, income statement recognition of pension plan costs has been deferred until costs are recovered through rates.  See Note 3 for information on Idaho Power's revenue sharing mechanism approved by the IPUC, which resulted in additional Idaho pension expense of $5.8 million for the nine months endedSeptember 30, 2012.

During the nine months endedSeptember 30, 2012, Idaho Power contributed $44.3 million to its defined benefit pension plan. Idaho Power has no further funding requirements to the defined benefit pension plan for 2012.

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11.  INVESTMENTS IN EQUITY SECURITIES

Investments in securities classified as available-for-sale securities are reported at fair value, using either specific identification or average cost to determine the cost for computing gains or losses.  Any unrealized gains or losses on available-for-sale securities are included in other comprehensive income.

The table below summarizes investments in equity securities by IDACORP and Idaho Power as of September 30, 2012 and December 31, 2011 (in thousands of dollars).

	September 30, 2012						December 31, 2011
	Gross Unrealized Gain		Gross Unrealized Loss		Fair Value		Gross Unrealized Gain		Gross Unrealized Loss		Fair Value
Available-for-sale securities	$	6,694	$	—	$	25,553	$	4,220	$	1	$	22,205

At the end of each reporting period, IDACORP and Idaho Power analyze securities in loss positions to determine whether they have experienced a decline in market value that is considered other-than-temporary.  At September 30, 2012, no securities were in an unrealized loss position. At December 31, 2011, one security was in an immaterial unrealized loss position. No other-than-temporary impairment was recognized for this security due to the limited severity and duration of the unrealized loss position.

There were no sales of available-for-sale securities during the three and nine months endedSeptember 30, 2012 or 2011.

12.  DERIVATIVE FINANCIAL INSTRUMENTS

Commodity Price Risk

Idaho Power is exposed to market risk relating to electricity, natural gas, and other fuel commodity prices, all of which are heavily influenced by supply and demand.  Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Market risk may also be influenced by market participants’ nonperformance of their contractual obligations and commitments, which affects the supply of or demand for the commodity.  Idaho Power uses derivative instruments, such as physical and financial forward contracts, futures, and swaps for both electricity and fuel to manage the risks relating to these commodity price exposures.  The objective of Idaho Power’s energy purchase and sale activity is to meet the demand of retail electric customers, maintain appropriate physical reserves to ensure reliability, and make economic use of temporary surpluses that may develop. Idaho Power has an energy risk management policy and an associated energy risk management standard that are collectively intended to systematically identify, measure, evaluate, and manage both the physical and financial exposures to business and market-driven uncertainties within a defined and controlled framework, in collaboration with representatives of Idaho Power's customers. Idaho Power’s energy risk management committee administers the company’s energy risk management standard and monitors compliance. The energy risk management committee is comprised of certain Idaho Power officers, including the chief risk officer, and other members of management. Idaho Power's board of directors also has a substantial role in oversight of enterprise risk management.

As part of its resource procurement and management operations, Idaho Power engages in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve load obligations and the use of these resources to capture available economic value. Idaho Power purchases and sells wholesale electric capacity and energy and fuel as part of the process of acquiring and balancing resources to serve its load obligations. This involves Idaho Power making continuing projections of resource needs and of loads, which are dependent on (among other things) estimates of usage and weather. On the basis of these projections, Idaho Power makes purchases and sales of electric capacity and energy and fuel to match expected resources to expected electric load requirements. Idaho Power's optimization process includes entering into hedging transactions to manage associated risks.

All commodity-related derivative instruments not meeting the normal purchases and normal sales exception to derivative accounting are recorded at fair value on the balance sheet.  Because of Idaho Power's PCA mechanisms, unrealized gains and losses associated with the changes in fair value of these derivative instruments are recorded as regulatory assets or liabilities. With the exception of forward contracts for the purchase of natural gas for use at Idaho Power’s natural gas generation facilities, Idaho Power’s physical forward contracts qualify for the normal purchases and normal sales exception.

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All of Idaho Power's derivative instruments have been entered into for the purpose of economically hedging forecasted purchases and sales, though none of these instruments have been designated as cash flow hedges under derivative accounting guidance. Idaho Power offsets fair value amounts recognized on its balance sheet related to derivative instruments executed with the same counterparty under the same master netting agreement.

Derivative Instrument Summary

The table below presents the fair values and locations of derivative instruments not designated as hedging instruments recorded on the balance sheets at September 30, 2012 and December 31, 2011 (in thousands of dollars).

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value
September 30, 2012
Current:
Financial swaps	Other current assets	$	5,885	Other current assets	$	1,781
Financial swaps	Other current liabilities	1,930		Other current liabilities	4,582
Forward contracts	Other current assets	183
Long-term:
Financial swaps	Other assets	213		Other assets	115
Financial swaps	Other liabilities	171		Other liabilities	314
Forward contracts	Other assets	188
Total		$	8,570		$	6,792
December 31, 2011
Current:
Financial swaps	Other current assets	$	4,361	Other current assets	$	1,036
Financial swaps	Other current liabilities	1,526		Other current liabilities	4,755
Forward contracts	Other current assets	70		Other current liabilities	1,370
Long-term:
Financial swaps	Other assets	359		Other liabilities	108
Total		$	6,316		$	7,269

The table below presents the gains and losses on derivatives not designated as hedging instruments for the three and nine months endedSeptember 30, 2012 and 2011 (in thousands of dollars).

		Gain/(Loss) on Derivatives Recognized
		in Income(1)
	Location of Realized Gain/(Loss) on Derivatives Recognized in Income	Three months ended						Nine months ended
		September 30						September 30
		2012			2011			2012			2011
Financial swaps	Off-system sales	$	1,793		$	441		$	11,703		$	6,947
Financial swaps	Purchased power	(2,479		)	(6,982		)	(5,631		)	(6,954		)
Financial swaps	Fuel expense	(2,516		)	115			(6,233		)	501
Financial swaps	Other operations and maintenance	(145		)	120			(166		)	347
Forward contracts	Fuel expense	(1,778		)	—			(1,778		)	—

⁽¹⁾  Excludes changes in fair value of derivatives, which are recorded on the balance sheet as regulatory assets or regulatory liabilities.

Settlement gains and losses on electricity swap contracts are recorded on the income statement in off-system sales or purchased power depending on the forecasted position being economically hedged by the derivative contract.  Settlement gains and losses on both financial and physical contracts for natural gas are reflected in fuel expense.  Settlement gains and losses on diesel derivatives are recorded in other operations and maintenance expense.  See Note 13 for additional information concerning the determination of fair value for Idaho Power’s assets and liabilities from price risk management activities.

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The table below presents the volumes of derivative commodity forward contracts and swaps outstanding at September 30, 2012 and 2011.

		September 30,
Commodity	Units	2012	2011
Electricity purchases	MWh	339,790	197,800
Electricity sales	MWh	1,691,650	1,038,095
Natural gas purchases	MMBtu	16,691,024	2,292,738
Natural gas sales	MMBtu	2,911,039	77,500
Diesel purchases	Gallons	263,167	266,375

Credit Risk

Credit risk relates to the potential losses that Idaho Power would incur as a result of non-performance by counterparties of their contractual obligations to deliver energy or make financial settlements. Idaho Power often extends credit to counterparties and customers and is exposed to the risk that it may not be able to collect amounts owed to it. Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are established. Should a counterparty fail to perform, Idaho Power may be required to honor the underlying commitment or to replace existing contracts with contracts at then-current market prices. Idaho Power manages these risks by establishing appropriate credit and concentration limits on transactions with counterparties and requiring contractual guarantees, cash deposits, or letters of credit from counterparties or their affiliates, as deemed necessary. Idaho Power actively monitors credit risk exposure through reviews of counterparty credit quality, corporate-wide counterparty credit exposure, and corporate-wide counterparty concentration levels.   Further, Idaho Power’s physical power contracts are under Western Systems Power Pool agreements, physical gas contracts are under North American Energy Standards Board contracts, and financial transactions are under International Swaps and Derivatives Association, Inc. contracts. These contracts contain adequate assurance clauses requiring collateralization if a counterparty has debt that is downgraded below investment grade by at least one rating agency.  The standardized agreements typically allow for the netting or offsetting of positive and negative exposures associated with a single counterparty or affiliated group.

Idaho Power maintains margin agreements with certain counterparties and margin calls are routinely made and/or received. Margin calls are triggered when exposures exceed predetermined contractual limits or when there are changes in a counterparty’s creditworthiness. Movements in electricity and fuel prices can generate exposure levels in excess of these contractual limits. Negotiating for collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.

At September 30, 2012, Idaho Power did not have material credit risk exposure from financial instruments, including derivatives.   

Credit-Contingent Features

Certain of Idaho Power's derivative instruments contain provisions that require Idaho Power's unsecured debt to maintain an investment grade credit rating from Moody's Investors Service and Standard & Poor's Ratings Services.  If Idaho Power's unsecured debt were to fall below investment grade, it would be in violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions.  The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position at September 30, 2012, was $7.2 million.  Idaho Power posted $1.2 million of cash collateral related to this amount.  If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2012, Idaho Power would have been required to post $4.4 million of additional cash collateral to its counterparties. 

13.  FAIR VALUE MEASUREMENTS

IDACORP and Idaho Power have categorized their financial instruments into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique.  The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).  If the inputs used to measure the financial instruments fall within different levels of the hierarchy, the categorization is based on the lowest level input that is significant to the fair value measurement of the instrument.

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Financial assets and liabilities recorded on the condensed consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:

•        Level 1:  Financial assets and liabilities whose values are based on unadjusted quoted prices for identical assets or liabilities in an active market that IDACORP and Idaho Power has the ability to access.

•        Level 2:  Financial assets and liabilities whose values are based on the following:

a)         Quoted prices for similar assets or liabilities in active markets;

b)         Quoted prices for identical or similar assets or liabilities in non-active markets;

c)         Pricing models whose inputs are observable for substantially the full term of the asset or liability; and

d)         Pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the asset or liability.

IDACORP and Idaho Power Level 2 inputs are based on quoted market prices adjusted for location using corroborated, observable market data.

•        Level 3:  Financial assets and liabilities whose values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.  These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.

An item recorded at fair value is reclassified between levels when changes in the nature of valuation inputs cause the item to no longer meet the criteria for the level in which it was previously categorized.

Idaho Power’s derivatives are contracts entered into as part of its management of loads and resources.  Electricity swaps are valued on the Intercontinental Exchange with quoted prices in an active market.  Natural gas and diesel derivative valuations are performed using New York Mercantile Exchange (NYMEX) pricing, adjusted for location basis, which are also quoted under NYMEX.  Trading securities consist of employee-directed investments held in a Rabbi Trust and are related to an executive deferred compensation plan.  Available-for-sale securities are related to the SMSP and are held in a Rabbi Trust and are actively traded money market and equity funds with quoted prices in active markets. Notes receivable are related to Ida-West and are valued based on unobservable inputs, including discounted cash flows, which are partially based on forecasted hydroelectric conditions. Long-term debt is not traded on an exchange and is valued using quoted rates for similar debt in active markets. There were no material changes in valuation techniques or inputs during the nine months ended September 30, 2012 or the year ended December 31, 2011.

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The table below presents information about IDACORP’s and Idaho Power’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011 (in thousands of dollars).  IDACORP’s and Idaho Power’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy.  There were no material transfers between levels for the periods presented. 

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
September 30, 2012
Assets:
Derivatives	$	944	$	3,629	$	—	$	4,573
Money market funds	100		—		—		100
Trading securities:  Equity securities	2,456		—		—		2,456
Available-for-sale securities:  Equity securities	25,553		—		—		25,553
Liabilities:
Derivatives	$	322	$	2,472	$	—	$	2,794
December 31, 2011
Assets:
Derivatives	$	3,654	$	100	$	—	$	3,754
Money market funds	100		—		—		100
Trading securities:  Equity securities	3,439		—		—		3,439
Available-for-sale securities:  Equity securities	22,205		—		—		22,205
Liabilities:
Derivatives	$	405	$	4,302	$	—	$	4,707

The table below presents the carrying value and estimated fair value of financial instruments that are not reported at fair value, as of September 30, 2012 and December 31, 2011, using available market information and appropriate valuation methodologies.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.  Cash and cash equivalents, deposits, customer and other receivables, notes payable, accounts payable, interest accrued, and taxes accrued are reported at their carrying value as these are a reasonable estimate of their fair value.  The estimated fair values for notes receivable and long-term debt are based upon quoted market prices of the same or similar issues or discounted cash flow analysis as appropriate. 

	September 30, 2012				December 31, 2011
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(thousands of dollars)
IDACORP
Assets:
Notes receivable (1)	$	3,097	$	3,097	$	3,097	$	3,097
Liabilities:
Long-term debt (1)	1,540,663		1,840,608		1,491,727		1,737,912
Idaho Power
Liabilities:
Long-term debt (1)	$	1,540,663	$	1,840,608	$	1,491,727	$	1,737,912

⁽¹⁾ Notes receivable and long-term debt are categorized as Level 3 and Level 2, respectively, of the fair value hierarchy, as defined earlier in this Note 13.

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14.  SEGMENT INFORMATION

IDACORP’s only reportable segment is utility operations.  The utility operations segment’s primary source of revenue is the regulated operations of Idaho Power.  Idaho Power’s regulated operations include the generation, transmission, distribution, purchase, and sale of electricity.  This segment also includes income from IERCo, a wholly-owned subsidiary of Idaho Power that is also subject to regulation and is a one-third owner of BCC, an unconsolidated joint venture.

IDACORP’s other operating segments are below the quantitative and qualitative thresholds for reportable segments and are included in the “All Other” category in the table below.  This category is comprised of IFS’s investments in affordable housing developments and historic rehabilitation projects, Ida-West’s joint venture investments in small hydroelectric generation projects, the remaining activities of energy marketer IE, which wound down its operations in 2003, and IDACORP’s holding company expenses.

The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars). 

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2012:
Revenues	$	332,757	$	1,262	$	—		$	334,019
Net income attributable to IDACORP, Inc.	89,596		2,473		—			92,069
Total assets as of September 30, 2012	5,119,384		103,117		(14,864		)	5,207,637
Three months ended September 30, 2011:
Revenues	$	308,045	$	1,585	$	—		$	309,630
Net income attributable to IDACORP, Inc.	104,872		2,195		—			107,067
Nine months ended September 30, 2012:
Revenues	$	826,788	$	3,074	$	—		$	829,862
Net income attributable to IDACORP, Inc.	150,125		2,174		—			152,299
Nine months ended September 30, 2011:
Revenues	$	793,031	$	3,076	$	—		$	796,107
Net income attributable to IDACORP, Inc.	155,420		2,288		—			157,708

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

IDACORP, Inc.

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet of IDACORP, Inc. and subsidiaries (the “Company”) as of September 30, 2012, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2012 and 2011, and of equity and cash flows for the nine-month periods ended September 30, 2012 and 2011.  These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of IDACORP, Inc. and subsidiaries as of December 31, 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2012, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2011 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 1, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Idaho Power Company

Boise, Idaho

We have reviewed the accompanying condensed consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary (the “Company”) as of September 30, 2012, and the related condensed consolidated statements of income and comprehensive income for the three-month and nine-month periods ended September 30, 2012 and 2011, and of cash flows for the nine-month periods ended September 30, 2012 and 2011.  These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters.  It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole.  Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization of Idaho Power Company and subsidiary as of December 31, 2011, and the related consolidated statements of income, comprehensive income, retained earnings, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2012, we expressed an unqualified opinion on those consolidated financial statements.  In our opinion, the information set forth in the accompanying condensed consolidated balance sheet and statement of capitalization as of December 31, 2011 is fairly stated, in all material respects, in relation to the consolidated balance sheet and statement of capitalization from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

November 1, 2012

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ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

(Megawatt-hours (MWh) and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.)

INTRODUCTION

In Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), the general financial condition and results of operations for IDACORP, Inc. and its subsidiaries (collectively, IDACORP) and Idaho Power Company and its subsidiary (collectively, Idaho Power) are discussed. While reading the MD&A, please refer to the accompanying condensed consolidated financial statements of IDACORP and Idaho Power, and the notes thereto. This discussion updates the MD&A included in the Annual Report on Form 10-K for the year ended December 31, 2011, and should also be read in conjunction with the information in that report. The results of operations for an interim period generally will not be indicative of results for the full year.

IDACORP is a holding company formed in 1998 whose principal operating subsidiary is Idaho Power.  IDACORP’s common stock is listed and trades on the New York Stock Exchange under the trading symbol “IDA.” Idaho Power is an electric utility with a service territory covering approximately 24,000 square miles in southern Idaho and eastern Oregon.  Idaho Power provided electric service to approximately 500,000 general business customers as of September 30, 2012.  As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the Idaho Public Utilities Commission (IPUC) and the Oregon Public Utility Commission (OPUC), which determine the rates that Idaho Power charges to its general business customers.  Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its Federal Energy Regulatory Commission (FERC) tariff and to provide transmission services under its FERC open access transmission tariff (OATT).  Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, and to seek to earn a return on investment.

Idaho Power generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its Idaho and Oregon service territories, as well as from the wholesale sale and transmission of electricity.  Idaho Power’s revenues and income from operations are subject to fluctuations during the year due to the impacts of seasonal weather conditions on demand for electricity, availability of water for hydroelectric generation, price changes, customer usage patterns (which are affected in large part by the condition of the local economy), and the availability and price of purchased power and fuel.  Idaho Power is a dual peaking utility that typically experiences its highest retail energy sales during the summer irrigation and cooling season, with a lower peak in the winter that generally results from heating demand.  Idaho Power has implemented a tiered-rate structure and seasonal rates. Both mechanisms increase the rates customers pay during higher-usage periods based on the amount of usage and time of year and are premised on encouraging energy efficiency during higher-usage periods and reflect the higher cost of providing service in those periods. These rate structures also contribute to seasonal fluctuations in earnings and revenues. IDACORP’s and Idaho Power’s financial condition are also affected by regulatory decisions, through which Idaho Power seeks to recover its costs on a timely basis, and to earn an authorized return on investment, and by the ability to obtain financing through the issuance of debt and/or equity securities.

IDACORP’s other subsidiaries include IDACORP Financial Services, Inc. (IFS), an investor in affordable housing and other real estate investments; Ida-West Energy Company, an operator of small hydroelectric generation projects that satisfy the requirements of the Public Utility Regulatory Policies Act of 1978 (PURPA); and IDACORP Energy, a marketer of energy commodities, which wound down operations in 2003. Idaho Power is the parent of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines and supplies coal to the Jim Bridger generating plant owned in part by Idaho Power.

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EXECUTIVE OVERVIEW

Brief Overview of Third Quarter 2012 Financial Results

IDACORP's earnings were $1.84 per diluted share for the quarter ended September 30, 2012, compared to $2.16 per diluted share for the same quarter in 2011. IDACORP's results in the third quarter of 2012 were positively impacted by general rate increases implemented during the year, but earnings for the quarter were lower than the third quarter of last year due to the financial statement impact of a tax method change recognized last year. These results, including a quantification of their respective impacts, are discussed in detail below.

Overview of General Factors and Trends Affecting Results of Operations and Financial Condition

IDACORP's and Idaho Power's results of operations and financial condition are affected by regulatory, economic, and other factors, many of which are described below.

Emphasis on Timely Regulatory Cost Recovery:  The price that regulators authorize Idaho Power to charge for electric service is a major factor in determining IDACORP's and Idaho Power's results of operations and financial condition.  Because of the significant impact of ratemaking decisions on Idaho Power's business and financial condition, the company continues to focus on timely recovery of its costs through filings with the company's regulators, including the IPUC, the OPUC, and the FERC. Effective implementation of Idaho Power's purposeful regulatory strategy is particularly important in an economic climate that puts more pressure on regulators to limit rate increases or otherwise take actions to limit the potential adverse impact of rate increases on customers, while at the same time the company requires rate increases to recover costs of providing reliable service. Particularly notable regulatory developments that have impacted or that IDACORP and Idaho Power expect will impact results, each of which is discussed in more detail under "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report, are listed below. Additional important regulatory matters are also discussed in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Proceeding	Description	Status
Idaho General Rate Case Settlement	General rate case, requesting an increase in Idaho-jurisdiction base rates	IPUC approved a $34.0 million increase in rates, effective January 1, 2012
Langley Gulch Power Plant	Request for recovery of and return on Idaho Power's investment in the Langley Gulch power plant, including operating costs	IPUC approved a $58.1 million increase in rates, effective July 1, 2012; OPUC approved a $3.0 million increase in rates effective October 1, 2012
Idaho Power Cost Adjustment (PCA)	Annual Idaho-jurisdiction PCA mechanism rate change	IPUC approved a $43.0 million increase in rates, effective only for the period from June 1, 2012 to May 31, 2013 (1)
Revenue Sharing	Rate adjustment pursuant to January 2010 and December 2011 settlement agreements(2)	IPUC approved a $27.1 million decrease in rates, effective only for the period from June 1, 2012 to May 31, 2013(2)
Idaho Depreciation for Non-AMI Meters	Application for removal from rates of accelerated depreciation expense associated with non-advanced metering infrastructure (AMI) metering equipment	IPUC approved a $10.6 million decrease in rates and associated depreciation expense, effective June 1, 2012
Oregon General Rate Case Settlement	General rate case, requesting an increase in Oregon-jurisdiction base rates	OPUC approved a $1.8 million increase in rates, effective March 1, 2012

(1) The rate change for the Idaho PCA was partially offset by the revenue-sharing order issued pursuant to the January 2010 and December 2011 settlement agreements.

(2) Idaho Power's revenue-sharing arrangements had two components: (a) a PCA mechanism component, which reduced net rates by $27.1 million, and (b) a pension balancing account component, which resulted in a $20.3 million net reduction to Idaho Power's pension regulatory asset (reducing Idaho customers' future obligation). Idaho Power recorded the $27.1 million revenue reduction and $20.3 million pension regulatory asset reduction in 2011.

In addition to the rate changes listed in the table above, in December 2011 the IPUC approved a settlement stipulation, separate from the Idaho general rate case settlement, that permits Idaho Power to amortize additional accumulated deferred investment tax credits (ADITC) to help achieve a minimum 9.5 percent rate of return on year-end equity in the Idaho jurisdiction (Idaho

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ROE) in 2012, 2013, and 2014, subject to prescribed limits and conditions. The settlement stipulation also provides for the potential sharing between the company and customers of Idaho-jurisdictional earnings in excess of specified levels of Idaho ROE. The specific terms of the settlement stipulation are described in "Regulatory Matters" in this MD&A and in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report. While providing no assurance that Idaho Power will obtain a 9.5 percent Idaho ROE in any of the years, IDACORP and Idaho Power believe the ability to amortize additional ADITC provides an element of earnings stability for the period from 2012 to 2014. Based on Idaho Power's estimate of full year 2012 Idaho ROE as of the date of this report, Idaho Power does not anticipate the need to amortize additional ADITC in 2012. Based on the terms of the December 2011 settlement stipulation, Idaho Power recorded during the third quarter of 2012 a $6.3 million provision against current revenues, as a benefit to Idaho customers in the form of a future rate reduction, and an additional $5.8 million of pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will be collected from customers in the future. As discussed below, Idaho Power recorded $18.1 million for the impact of a similar sharing mechanism in the third quarter of 2011.

Economic Conditions and Customer/Load Growth: When seeking to predict utility load changes for both short-term load forecasts and long-term infrastructure planning purposes, Idaho Power monitors a number of economic indicators, including employment rates, growth in customer numbers, and foreclosure rates and other housing-related data on both a national scale and within and around Idaho Power's service territory. Economic conditions can impact consumer demand for electricity, collectability of accounts, the volume of off-system sales, and Idaho Power's need for purchased power to meet demand.   

Since 2008, economic conditions in Idaho Power's service territory have been relatively weak.  However, a number of improvements in economic conditions have occurred over the last year and a half. After peaking at 10.0 percent in early 2011, the service area unemployment rate fell to 8.4 percent by the end of 2011 and reached 6.9 percent by the end of September 2012, according to Idaho Department of Labor data. The housing market in Idaho Power's service territory has improved when measured by foreclosure rates and the available supply and pricing of housing. Idaho Power also continues to experience customer growth. During the 12 months ended September 30, 2012, the customer growth rate in Idaho Power's service territory was approximately 1.1 percent—roughly twice the growth rate of the prior two years. By comparison, for the 20-year period ending in 2011 the average annual customer growth rate in Idaho Power's service territory was 2.6 percent. Based on this data, Idaho Power predicts positive customer growth within its service territory in the next few years, though likely at a rate below the 20-year historical annual average. The foregoing general economic data and outlook is based, in part, on independent government and industry publications, reports by market research firms, or other independent sources. While IDACORP and Idaho Power believe that these publications and other sources are reliable, the companies have not independently verified such data and can make no representation as to its accuracy.

Idaho Power cannot predict the timing of, and pace at which, economic recovery may occur in Idaho Power's service territory.  As a result, Idaho Power continues to manage costs while executing its three-part strategy of responsible planning, responsible development and protection of resources, and responsible energy use.

Weather Conditions and Associated Impacts:  Weather and agricultural growing conditions have a significant impact on energy sales and the seasonality of those sales. Relatively low and high temperatures result in greater energy usage for heating and cooling, respectively.  During the agricultural growing season, which in large part occurs during the second and third quarters, irrigation customers use electricity to operate irrigation pumps.  A four-percent increase in energy use by customers during the first nine months of 2012 compared to the first nine months of 2011 was largely attributable to agricultural growing conditions from April through September that required above average use of irrigation equipment and electric power to operate that equipment. Increased loads from irrigation equipment were particularly pronounced during the second quarter of 2012. As noted above, Idaho Power also has tiered rates and seasonal rates, which contribute to increased revenues during higher-load periods, most notably the third quarter of each year when customer demand is typically at its peak. On July 12, 2012, Idaho Power achieved a record load demand of 3,245 MW. The previous record load demand was 3,214 MW, set on June 30, 2008. At the time of the record load demand, Idaho Power had deployed 61 MW of demand response programs.

Idaho Power's hydroelectric facilities comprise approximately one-half of Idaho Power's nameplate generation capacity. The availability and volume of hydroelectric power depends on the amount of snow pack in the mountains upstream of Idaho Power's hydroelectric facilities, reservoir storage, springtime snow pack run-off, base flows in the Snake River, spring flows, rainfall, water leases and other water rights, and other weather and stream flow considerations.  Idaho Power expects hydroelectric generation during 2012 to be in the range of 7.8 to 8.2 million megawatt-hours (MWh), based on reservoir storage levels and forecasted weather conditions as of the date of this report, compared to actual generation of 10.9 million MWh in 2011 and 7.3million MWh in 2010. Median annual hydroelectric generation is 8.6 million MWh. For the nine months ended September 30, 2012, hydroelectric generation comprised 62 percent of Idaho Power’s total system generation.  Hydroelectric generation decreased 24 percent in the first nine months of 2012 compared to the first nine months of 2011 as a result of slightly below normal hydroelectric conditions in the current year. When hydroelectric generation is reduced Idaho

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Power must rely on more expensive generation sources and purchased power; however, most of the increase in power supply costs is deferred as a regulatory asset and collected from customers through the PCA mechanisms. Conversely, in periods of greater hydroelectric generation most of the resulting decrease in power supply costs that typically occurs is returned to customers through the PCA mechanisms.

Where favorable hydroelectric generating conditions exist for Idaho Power, they also may be abundant for other Pacific Northwest hydroelectric facility operators, thus increasing the available supply of lower-cost power and depressing regional wholesale market prices, which impacts the revenue Idaho Power receives from off-system sales of its excess power. Conversely, when hydroelectric generating conditions are poor, wholesale market prices may be higher due to lower supply, but Idaho Power would have less surplus energy available for sale into the wholesale markets.

Fuel and Purchased Power Expense:  In addition to hydroelectric generation and power it purchases in the wholesale markets, Idaho Power relies significantly on coal and natural gas to fuel its generation facilities.  Fuel costs are impacted by electricity sales volumes, the terms of contracts for fuel, Idaho Power's power generation capacity, the rate of expansion of alternative energy generation sources such as wind energy, the availability of hydroelectric generation resources, transmission capacity, energy market prices, and Idaho Power's hedging program for managing fuel costs. Operation of Idaho Power's newly constructed Langley Gulch power plant increases Idaho Power's use of natural gas as a generation source, and thus its exposure to volatility in natural gas prices.

Purchased power costs are impacted by the terms of contracts for purchased power, the rate of expansion of alternative energy generation sources such as wind energy, and wholesale energy market prices. Idaho Power is generally obligated to purchase power from PURPA generation projects at a specified price regardless of the then-current load demand or wholesale energy market prices. This increases the likelihood that Idaho Power will be required to reduce output from its lower-cost hydroelectric and fossil fuel-fired generation resources and may be required to sell in the wholesale power market the power it purchases from PURPA projects at a significant loss. Integration of intermittent, non-dispatchable resources (such as wind energy) into Idaho Power's portfolio also creates a number of complex operational risks and challenges, which Idaho Power is working to address, including through evaluation of the results of a recent comprehensive wind integration study. Notably, integration of these sources of power into Idaho Power's portfolio does not eliminate Idaho Power's need to construct facilities and infrastructure that provide reliable power. For instance, at the time Idaho Power reached its all-time system peak demand of 3,245 MW on July 12, 2012, wind resources on Idaho Power's system, representing roughly 500 MW of capacity, were contributing only 14 MW of power due to lack of wind.

The Idaho and Oregon PCA mechanisms mitigate in large part the potential adverse impacts of fluctuations in Idaho Power's power supply costs.  Idaho Power also uses physical and financial forward contracts for both electricity and fuel in order to manage the risks relating to fuel and power price exposures.

Regulatory and Environmental Compliance Costs and Expenditures:  Idaho Power is subject to extensive federal and state laws, policies, and regulations, as well as regulatory actions and audits.  Compliance with these requirements directly influences Idaho Power's operating environment and may significantly increase Idaho Power's operating costs.  Further, potential monetary and non-monetary penalties for a violation of applicable laws or regulations may be substantial.  Accordingly, Idaho Power has in place numerous compliance policies and initiatives, and frequently evaluates, updates, and supplements those policies and initiatives. In particular, environmental laws and regulations may, among other things, increase the cost of operating power generation plants and constructing new facilities, require that Idaho Power install additional pollution control devices at existing generating plants, or require that Idaho Power shut down certain power generation plants.  For instance, the Boardman coal-fired power plant, in which Idaho Power owns a 10-percent interest, is scheduled to cease coal-fired operations in 2020. As legislation and regulations concerning greenhouse gas emissions develop, Idaho Power assesses, when and to the extent determinable, the potential impact on the costs to operate its power generation facilities, as well as the willingness or ability of joint owners of power plants to fund any required pollution control equipment upgrades in lieu of early plant retirements.

Other Notable Matters and Areas of Focus

Pension Plans:  Idaho Power contributed $44.3 million to its defined benefit pension plan in the first nine months of 2012, $18.5 million in 2011, and $60.0 million in 2010, and expects to make additional significant cash contributions in the coming years. The primary impact of pension plan contributions is on cash flows. Idaho Power defers pension costs related to its Idaho jurisdiction until those costs are recovered through rates. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. In addition, the revenue sharing mechanism in Idaho Power's December 2011 settlement stipulation resulted in the recording of additional Idaho pension expense of $5.8 million during the three months ended September 30, 2012. 

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Water Management and Relicensing of Hydroelectric Projects: Because of Idaho Power's reliance on stream flow in the Snake River and its tributaries, Idaho Power participates in numerous proceedings and venues that may affect its water rights, seeking to preserve the long-term availability of its rights for use at its hydroelectric projects. Also, Idaho Power is involved in renewing federal licenses for the Hells Canyon Complex (HCC), its largest hydroelectric generation source, and recently received a 30-year license renewal from the FERC for its Swan Falls hydroelectric project.  Relicensing involves numerous environmental issues and substantial costs.  Idaho Power is working with the states of Idaho and Oregon, regulatory authorities, and interested parties to address concerns and take appropriate measures relating to the relicensing of Idaho Power's hydroelectric projects.  Given the number of parties and issues involved, Idaho Power's relicensing costs have been and will continue to be substantial.

Transmission Projects: Idaho Power continues to focus on expansion of its transmission system in an effort to improve system reliability and resource adequacy. Its most notable projects in progress include the proposed Boardman-to-Hemingway and Gateway West transmission projects. In January 2012, Idaho Power entered into cost-sharing arrangements with third parties for the permitting phases of both projects. Construction of these projects cannot commence until all federal, state, and local regulatory requirements are met. To further mitigate the risks associated with these projects, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC for the projects prior to construction. Based on Idaho Power's assessment of the status and future milestones for the Boardman-to-Hemingway project, Idaho Power has determined that an in-service date prior to 2018 is unlikely.

Environmental Sustainability Initiatives:As of the date of this report, Idaho Power is on-track to exceed the CO₂ emission intensity reduction goal it established in 2009. Reflecting its further commitment to that goal, Idaho Power management plans to recommend to its board of directors that the board extend for an additional two-year period the CO₂ emission intensity reduction goal, through 2015. At the same time, Idaho Power has been conducting a thorough analysis of the costs and methods for the integration of intermittent wind power into its energy portfolio, and expects to publicly release the results of that study during the fourth quarter of 2012. Further, in connection with its IRP process, Idaho Power has been conducting cost studies related to its jointly-owned coal-fired power plants, to determine whether plant upgrades that may be necessary to comply with environmental regulations are prudently incurred investments, or whether it is economically preferable to replace that generation with combined-cycle combustion turbine or other resources.

Summary of Third Quarter and Year-to-Date 2012 Financial Results

The following is a summary of Idaho Power's net income, net income attributable to IDACORP, Inc., and IDACORP's earnings per diluted share for the three- and nine-month periods ended September 30, 2012 and 2011: 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Idaho Power net income	$	89,596	$	104,872	$	150,125	$	155,420
Net income attributable to IDACORP, Inc.	$	92,069	$	107,067	$	152,299	$	157,708
Average outstanding shares – diluted (000’s)	50,080		49,622		49,990		49,499
IDACORP, Inc. earnings per diluted share	$	1.84	$	2.16	$	3.05	$	3.19

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The following table presents a reconciliation of net income attributable to IDACORP, Inc. for the three- and nine-month periods ended September 30, 2012 to the same periods in 2011 (items are in millions and are before tax unless otherwise noted):

	Three months ended						Nine months ended
Net income attributable to IDACORP, Inc. - September 30, 2011				$	107.1					$	157.7
Change in Idaho Power net income:
Rate and other regulatory changes, including pension expense recovery, power cost and fixed cost adjustment mechanisms	$	32.1					$	43.5
Increase in sales volumes	3.0						19.3
Change in payroll-related expenses	2.3						(4.7		)
Additional pension expense funded through sharing and rate increases	(5.8		)				(11.0		)
Increased depreciation expense, property tax, and other	(2.7		)				(1.8		)
Greater revenue sharing in 2011 than in 2012	11.8						11.8
Increase in Idaho Power operating income	40.7						57.1
Change in allowance for funds used during construction (AFUDC)	(4.2		)				1.2
Other net changes	(2.2		)				4.2
Change from removal of additional amortization of ADITC in 2011	6.8						—
Change in income tax expense	(56.4		)				(67.8		)
Total decrease in Idaho Power net income				(15.3		)				(5.3		)
Other net changes (net of tax)				0.3						(0.1		)
Net income attributable to IDACORP, Inc. - September 30, 2012				$	92.1					$	152.3

Third Quarter 2012 Net Income

IDACORP net income decreased $15.0 million for the third quarter of 2012 when compared with the same period in the prior year, largely a result of the effect of an IRS examination settlement recorded during the third quarter in the prior year, when Idaho Power recognized approximately $56.9 million of previously unrecognized tax benefits related to the uniform capitalization method agreement with the IRS for tax years 2009 and prior. Largely offsetting the decrease in income related to the prior year examination settlement were several rate changes that combined to increase operating income by $32.1 million. These rate increases were the result of increased rates from a general rate case that took effect on January 1, 2012, increased rates related to the Langley Gulch power plant that took effect on July 1, 2012, and the impact of other rate changes and regulatory mechanisms that were effective concurrent with the summer rate season. Higher sales volumes also increased operating income by $3.0 million, driven by customer growth and warmer temperatures, which increased energy demand to operate air conditioning systems.

Effect of Sharing on Operating Income	Three and nine months ended September 30,
	2012			2011			Change
Additional pension expense funded through sharing	$	(5.8	)	$	—		$	(5.8	)
Provision against current revenue as a result of sharing	(6.3		)	(18.1		)	11.8
Total	$	(12.1	)	$	(18.1	)	$	6.0

As a result of the rate and sales volume increases described above and their anticipated impact on annual net income, Idaho Power recorded a total of $12.1 million related to the settlement agreement approved by the IPUC in December 2011, which required sharing with customers a portion of 2012 Idaho-jurisdiction earnings exceeding a specified return on year-end equity. Of the total, $5.8 million was recorded as additional pension expense, which will benefit Idaho customers by reducing the amount of deferred pension expense that will need to be collected from customers in the future, and $6.3 million was a provision against current revenues to be refunded to customers through a future rate reduction. In the third quarter of 2011 Idaho Power recorded an $18.1 million provision against revenues to be refunded to customers.

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Year-to-Date Net Income

IDACORP's year-to-date net income was also impacted by the IRS examination settlements and sharing mechanisms discussed above, but only decreased $5.4 million compared to the same period in 2011. The impacts of changes in rates and other regulatory mechanisms and increased sales volumes offset most of the 2011 IRS examination settlements and sharing reserves. A warmer, drier spring in 2012 caused significant increases in irrigation usage when compared with the prior year. Warmer summer temperatures, which drove slight increases in residential usage in the third quarter, were offset by relatively mild winter temperatures experienced earlier in the year, which reduced sales to residential customers for heating purposes. In total, sales volume changes increased operating income by $19.3 million. A rate increase resulting from a general rate case in the Idaho jurisdiction that took effect on January 1, 2012, combined with increased rates related to the Langley Gulch power plant that took effect on July 1, 2012, and the impacts of other rate changes and regulatory mechanisms, increased operating income by $43.5 million.

Key Operating and Financial Metric Estimates for Full-Year 2012

IDACORP’s and Idaho Power’s estimates, as of the date of this report, for 2012 full year metrics are as follows:

	2012 Estimates
	Current (4)	Previous (5)
Idaho Power Operating & Maintenance Expense (millions)(1)	$335-$345	$325-$335
Idaho Power Additional Amortization of ADITC (millions)	No Change	None
Idaho Power Capital Expenditures (millions)(2)	No Change	$230-$235
Idaho Power Hydroelectric Generation (million MWh)(3)	7.8-8.2	7.5-8.5
Non-regulated subsidiary earnings and holding company expenses (millions)	No Change	$0.0-$3.0
(1) Increase in the range reflects the estimated amount of additional pension expense to be recognized related to the Idaho sharing arrangement. No expected impact to net income as a result of the increase.
(2)    The range for capital expenditures includes (among other items) the completion of the Langley Gulch power plant and expenditures for the siting and permitting of major transmission expansions for the Boardman-to-Hemingway and Gateway West transmission projects (net of ongoing payments from third parties participating as joint funders in the permitting projects), excluding AFUDC.
(3) Based on reservoir storage levels and forecasted weather conditions as of the date of this report.
(4) As of November 1, 2012.
(5) As of August 2, 2012, the date of filing of IDACORP's and Idaho Power's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012.

RESULTS OF OPERATIONS

This section of MD&A takes a closer look at the significant factors that affected IDACORP’s and Idaho Power’s earnings during the three and nine months endedSeptember 30, 2012.  In this analysis, the results for the three and nine months endedSeptember 30, 2012 are compared to the same periods in 2011. In MD&A, MWh and dollar amounts, other than earnings per share, are in thousands unless otherwise indicated.

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Utility Operations

The table below presents Idaho Power’s energy sales and supply (in thousands of MWh) for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
General business sales	4,304		4,239		10,941		10,524
Off-system sales	109		747		1,656		2,794
Total energy sales	4,413		4,986		12,597		13,318
Hydroelectric generation	1,649		2,790		6,630		8,683
Coal generation	1,653		1,482		3,505		3,370
Natural gas and other generation	410		83		610		124
Total system generation	3,712		4,355		10,745		12,177
Purchased power	1,026		974		2,871		2,157
Line losses	(325	)	(343	)	(1,019	)	(1,016	)
Total energy supply	4,413		4,986		12,597		13,318

General Business Revenues:  The table below presents Idaho Power’s general business revenues and MWh sales for the three and nine months endedSeptember 30, 2012 and 2011 and the number of customers as of September 30, 2012 and 2011.

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenue
Residential	$	120,786		$	103,035		$	316,964		$	302,464
Commercial	72,519			61,630			181,810			169,229
Industrial	41,690			38,496			108,804			105,098
Irrigation	80,780			70,596			131,057			99,467
Total	315,775			273,757			738,635			676,258
Provision for sharing	(6,300		)	(18,100		)	(6,300		)	(18,100		)
Deferred revenue related to HCC relicensing AFUDC(1)	(3,409		)	(3,344		)	(8,310		)	(8,277		)
Total general business revenues	$	306,066		$	252,313		$	724,025		$	649,881
Volume of Sales (MWh)
Residential	1,285			1,246			3,757			3,786
Commercial	1,044			1,035			2,911			2,867
Industrial	793			783			2,333			2,294
Irrigation	1,182			1,175			1,940			1,577
Total MWh sales	4,304			4,239			10,941			10,524
Customer Count (period end)
Residential	414,640			410,079
Commercial	65,782			65,061
Industrial	119			124
Irrigation	19,071			18,807
Total customers	499,612			494,071

⁽¹⁾ As part of its January 30, 2009 general rate case order, the IPUC allowed Idaho Power to recover AFUDC for the HCC relicensing asset even though the relicensing process is not yet complete and the relicensing asset has not been placed in service. Idaho Power expects to collect approximately $10.7 million annually in the Idaho jurisdiction, but will defer revenue recognition of the amounts collected until the license is issued and the asset is placed in service under the new license.

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Changes in rates and changes in customer demand are the primary reasons for fluctuations in general business revenue from period to period. The table below presents the rate changes that significantly impacted revenue levels for the third quarter and the first nine months of 2012 compared to the same periods in 2011.

Description	Effective Date	Percentage Rate Increase (Decrease)		Annualized $ Impact (millions)
2011 Idaho PCA	6/1/2011	(4.8	)%	$	(40	)
2011 Idaho pension expense recovery	6/1/2011	1.4	%	12
2011 Idaho general rate case settlement agreement	1/1/2012	4.1	%	34
2012 Idaho PCA	6/1/2012	5.1	%	43
2012 Idaho non-AMI meter depreciation	6/1/2012	(1.3	)%	(11		)
2012 Idaho Langley Gulch	7/1/2012	6.8	%	58

The primary factors influencing customer demand are weather and economic conditions. Extreme temperatures increase sales to customers who use electricity for cooling and heating, and moderate temperatures decrease sales. Precipitation levels during the agricultural growing season affect sales to customers who use electricity to operate irrigation pumps, with increased precipitation reducing electricity sales. Boise, Idaho weather conditions for the three and nine months endedSeptember 30, 2012 and 2011 are included in the table below.

	Three months ended September 30,			Nine months ended September 30,
	2012	2011	Normal	2012	2011	Normal
Heating degree-days (1)	17	10	121	2,865	3,438	3,319
Cooling degree-days (1)	1,074	969	751	1,273	1,054	934
(1) Heating and cooling degree-days are common measures used in the utility industry to analyze the demand for electricity and indicate when a customer would use electricity for heating and air conditioning. A degree-day measures how much the average daily temperature varies from 65 degrees. Each degree of temperature above 65 degrees is counted as one cooling degree-day, and each degree of temperature below 65 degrees is counted as one heating degree-day.

General business revenue increased $53.8 million for the quarter and $74.1 million for the year-to-date compared to the same periods in 2011. The factors affecting general business revenues are discussed in more detail below.

• Rates.  The rate changes listed above combined to increase general business revenue by $43.9 million for the quarter and $48.8 million year-to-date compared to the same periods in 2011. Rates are seasonally adjusted and based on a tiered rate structure that provides for higher rates during higher-usage periods. These seasonal and tiered rate structures contribute to seasonal fluctuations in revenues and earnings. The revenue impact of several of the rate changes was directly offset by associated changes in operating expenses. For example, Idaho PCA amortization expense was reduced $6.4 million for the quarter and $19.5 million year-to-date compared to the same periods in 2011 due to the change in the corresponding Idaho PCA rate in the prior year. Idaho-jurisdiction pension expense recovery and FCA rate changes were fully offset by related amortizations.

• Sharing. A part of the increase in revenue resulted from revenue sharing mechanisms in place in both years. The impact of these mechanisms is recorded as a reduction to general business revenue. For both the quarter and year-to-date, $6.3 million was recorded in the current year and $18.1 million was recorded in the prior year, for a net increase to general business revenue of $11.8 million in the current year. The revenue sharing mechanisms are associated with two Idaho regulatory agreements that provide for the sharing of Idaho-jurisdiction earnings exceeding a specified Idaho ROE. The amounts recorded reflect amounts to be refunded to customers. The smaller amount recorded in the current year when compared with the same period in the prior year is partially due to changes in the terms of the mechanism in place in each year.

• Customers.  Moderate customer growth drove an increase in overall MWh sales for the quarter and year-to-date. Total customers increased 1.0 percent for the quarter and 0.9 percent year-to-date compared to the same periods in 2011. Customer growth was offset by changes in revenue related to a large industrial customer. These changes combined caused a $1.2 million decrease in general business revenues for the quarter and increased general business revenues by $3.3 million year-to-date when compared to the same periods in 2011. 

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• Usage.  The revenue impact of customer growth was also offset for the third quarter of 2012 by lower usage per customer, which decreased general business revenue by $0.7 million compared to the third quarter of 2011. Higher residential usage per customer, which increased 2.1 percent for the quarter due to a 10.8 percent increase in cooling degree days, drove demand for electricity to operate air conditioning units. Commercial usage per customer also increased by 0.7 percent for the quarter when compared with the same period in 2011. Offsetting these increases was decreased irrigation usage per customer, which declined 4.1 percent when compared to the same period in 2011.

For the nine months ended September 30, 2012, higher usage per customer increased revenues by $10.2 million. Irrigation usage per customer was 13.8 percent higher for the period due to agricultural growing conditions in the second quarter, including warmer temperatures that allowed for earlier planting of crops, and due to lower relative springtime precipitation, which resulted in greater use of irrigation pumps compared to the same growing season in the prior year. For the year-to-date, commercial usage per customer increased 1.2 percent, while residential per customer usage decreased by 1.6 percent. The modest decrease in year-to-date residential usage per customer is due primarily to relatively mild winter and spring temperatures, which decreased demand for heating purposes.

Off-System Sales:  Off-system sales consist primarily of long-term sales contracts and opportunity sales of surplus system energy.  The table below presents Idaho Power’s off-system sales for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Revenue	$	4,826	$	24,083	$	43,953	$	74,648
MWh sold	109		747		1,656		2,794
Revenue per MWh	$	44.28	$	32.24	$	26.54	$	26.72

For the quarter and the year-to-date, off-system sales revenue decreased by $19.3 million, or 80 percent, and $30.7 million, or 41 percent, respectively, as compared to the same periods in 2011. Off-system sales volumes decreased 85 percent for the quarter and 41 percent for the first nine months of 2012, as a result of decreased hydroelectric generation and increased system load when compared to the same periods in 2011. The decreases in volume were partially offset by a 37 percent increase in average prices for the quarter and modestly impacted by a 1 percent decrease in average prices for the first nine months of 2012.

Other Revenues:  The table below presents the components of other revenues for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Transmission services and other	$	13,455	$	13,145	$	37,839	$	37,491
Energy efficiency	8,410		18,504		20,971		31,011
Total other revenues	$	21,865	$	31,649	$	58,810	$	68,502

Other revenue decreased $9.8 million and $9.7 million for the third quarter and first nine months of 2012, respectively, compared to the same periods in 2011. Demand response incentive payments to customers, which had been treated as an energy efficiency expense and recovered through the energy efficiency rider in 2011 and prior, are being recorded as purchased power expense (discussed below) and recovered through the PCA mechanism during 2012, as discussed in Note 3 - "Regulatory Matters" to the condensed consolidated financial statements included in this report.

Most energy efficiency activities are funded through a rider mechanism on customer bills.  Energy efficiency program expenditures funded through the rider are reported as an operating expense with an equal amount of revenues recorded in other revenues, resulting in no net impact on earnings.  The cumulative variance between expenditures and amounts collected through the rider is recorded as a regulatory asset or liability pending future collection from or obligation to customers.  A liability balance indicates that Idaho Power has collected more than it has spent and an asset balance indicates that Idaho Power has spent more than it has collected.  As of September 30, 2012, Idaho Power’s total Idaho and Oregon jurisdictional energy efficiency rider balance was a net regulatory asset of $1.5 million.

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Purchased Power:  The table below presents Idaho Power’s purchased power expenses and volumes for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Expense
PURPA contracts	$	35,483	$	28,095	$	88,842	$	66,929
Other purchased power (including wheeling)	22,862		38,046		47,837		60,729
Demand response incentive payments	13,225		—		14,347		—
Total purchased power expense	$	71,570	$	66,141	$	151,026	$	127,658
MWh purchased
PURPA contracts	497		415		1,489		1,123
Other purchased power	529		559		1,382		1,034
Total MWh purchased	1,026		974		2,871		2,157
Cost per MWh from PURPA contracts	$	71.39	$	67.70	$	59.67	$	59.60
Cost per MWh from other sources	$	43.22	$	68.06	$	34.61	$	58.73
Weighted average - all sources	$	56.87	$	67.91	$	47.61	$	59.18

Purchased power expense increased $5.4 million, or 8 percent, in the third quarter of 2012 and $23.4 million, or 18 percent, in the first nine months of 2012, compared to the same periods in 2011. This increase was driven by the volume of mandated power purchases from cogeneration and small power production (CSPP) facilities pursuant to PURPA, which increased 20 percent for the quarter and 33 percent in the first nine months of 2012 due to new PURPA wind generation facilities coming on-line. In addition, for the year-to-date, there was less hydroelectric generation available than in the prior year, at the same time that loads increased.

The increases in contract purchases were partially offset by a 40 percent and 43 percent decrease in the average price of wholesale purchased power, excluding wheeling costs, for the quarter and the year-to-date, respectively. Further, beginning in June 2012, demand response program incentive payments were included in purchased power expenses, for recovery through base rates and the PCA mechanism, whereas in 2011 the incentives were recovered through the energy efficiency rider mechanism.  

Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the increased expense associated with PURPA power purchases is a corresponding increase in customer rates.

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Fuel Expense:  The table below presents Idaho Power’s fuel expenses and generation at its thermal generating plants for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,				Nine months ended September 30,
	2012		2011		2012		2011
Expense
Coal	$	41,905	$	35,805	$	90,041	$	81,050
Natural gas and other(1)	14,073		5,390		19,973		9,751
Total fuel expense	$	55,978	$	41,195	$	110,014	$	90,801
MWh generated
Coal	1,653		1,482		3,505		3,370
Natural gas and other(1)	410		83		610		124
Total MWh generated	2,063		1,565		4,115		3,494
Cost per MWh
Coal	$	25.35	$	24.16	$	25.69	$	24.05
Natural gas and other	$	34.32	$	64.94	$	32.74	$	78.64
Weighted average, all sources	$	27.13	$	26.32	$	26.73	$	25.99

⁽¹⁾ Excludes 129 MWh of generation from the Langley Gulch power plant in the second quarter of 2011 for which costs were capitalized during the construction and testing phase of the plant. The Langley Gulch power plant became commercially available on June 29, 2012.

Fuel expense increased $14.8 million, or 36 percent, in the third quarter of 2012 and $19.2 million, or 21 percent, in the first nine months of 2012 compared to the same periods in 2011, due principally to the following factors:

• Idaho Power's Langley Gulch plant came on line at the end of the second quarter of 2012. Operation of the plant accounted for $8.3 million of the increase in fuel expense for the quarter and the year-to-date. Idaho Power operated the plant to serve peak load. In addition, Idaho Power operated the plant to integrate intermittent resources and for economic dispatch opportunities.

• Generation from coal-fired facilities increased 12 percent for the quarter and 4 percent for the first nine months compared to the same periods in 2011. During the quarter, higher wholesale power prices and lower hydroelectric generation when compared with the same period in the prior year increased Idaho Power's reliance on its coal-fired plants to meet customer loads.

• Along with the increases in coal- and natural gas-fired electric generation, commodity prices were higher at the coal plants for the quarter and year-to-date when compared with the same periods in the prior year. Most fuel supply contracts are subject to changes in published indexes that are closely related to materials and supplies, labor, and diesel costs. In addition to commodity (variable) costs, both natural gas and coal expense include costs that are more fixed in nature for items such as capacity charges, transportation, and fuel handling. Period to period variances in fuel expense per MWh are noticeably impacted by these fixed charges when generation output is substantially different between the two periods. The relatively large cost per MWh for natural gas facilities during the three- and nine-month periods of 2011, as shown in the table above, was the result of the allocation of fixed costs over a low volume of output.

PCA Mechanisms:  Idaho Power's power supply costs (primarily purchased power and fuel, less off-system sales) can vary significantly from year to year, primarily because of the impacts of weather, system loads, and commodity markets.  To address the volatility of power supply costs, Idaho Power has PCA mechanisms in both the Idaho and Oregon jurisdictions.  These mechanisms allow Idaho Power to recover from or refund to customers most of the fluctuations in power supply costs.  Because of these mechanisms, the primary financial impacts of power supply cost variations is that cash is paid out but recovery from customers does not occur until a future period, or cash that is collected is refunded to customers in a future period, resulting in fluctuations in operating cash flows from year to year.

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PCA expense represents the effects of the Idaho and Oregon PCA mechanisms.  The table below presents the components of the Idaho and Oregon PCA mechanisms for the three and nine months endedSeptember 30, 2012 and 2011. 

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Idaho power supply cost (deferral) accrual	$	(36,320	)	$	(9,845	)	$	(25,709	)	$	25,756
Oregon power supply cost (deferral) accrual	—			(159		)	(1,523		)	1,159
Amortization of prior year authorized balances	(6,551		)	(185		)	(9,842		)	9,703
Total power cost adjustment expense	$	(42,871	)	$	(10,189	)	$	(37,074	)	$	36,618

The power supply accruals or deferrals represent the portion of that periods' power supply cost fluctuations accrued or deferred under the PCA mechanisms. Accruals represent additional costs recorded because actual power supply costs were less than the amount forecasted in PCA rates. The power supply cost deferral in the third quarter of 2012 is greater than in 2011 because actual power supply costs in 2012 were higher than the amounts forecasted in PCA rates. If actual power supply costs are greater than the amount forecasted in PCA rates, most of the excess is deferred. The amortization of the prior year’s balances represents the amounts being collected or refunded in the current PCA year that were deferred or accrued in the prior PCA year (the true-up component of the PCA).

Other Operations and Maintenance (O&M) Expenses:  Other O&M expense increased $5.4 million for the quarter and $13.8 million for the year-to-date as compared to the same periods in 2011. The changes in other O&M expense were due to the following:

• an increase in pension expense of $5.8 million and $11.0 million for the quarter and first nine months, respectively. This increase resulted from a $5.8 million third quarter sharing accrual under Idaho Power's December 2011 settlement agreement, which benefits Idaho customers through an offset to the deferred pension regulatory asset. The remainder of the year-to-date increase represents pension expenses that increased in June 2011 concurrent with increased recovery of deferred pension costs in rates;

• changes in labor and benefits costs, which declined $2.3 million for the quarter and increased $4.7 million year-to-date. These changes resulted from normal increases in employee wages and costs of providing employee benefits. The change for the quarter was also affected by variations in timing of labor expenses recorded in the current year compared to the prior year;

• increases in administrative and other costs of $3.2 million for the quarter and $7.4 million for the comparative year-to-date, primarily related to increases in consultant costs, software licenses and maintenance, and other purchased services. A significant portion of the increase related to a lower reimbursement from the U.S. Department of Energy for Smart Grid-related items in 2012 compared to 2011; and

• decreased thermal plant O&M costs of $0.7 million for the quarter and $9.0 million for the year-to-date related to costs for maintenance outages that occurred in 2011 that did not recur in 2012, as well as lower overall maintenance costs as the plants experienced less wear and tear due to lower utilization during the first half of 2012. The lower utilization was predominately driven by low wholesale energy prices in the region during that period.

Income Taxes

Income Tax Expense: IDACORP's and Idaho Power's income tax expense for the nine months endedSeptember 30, 2012, compared to the same period in 2011, increased $66.9 million and $67.8 million, respectively, primarily as a result of greater Idaho Power pre-tax earnings and IRS examination settlements in 2011, partially offset by a tax accounting method change at Idaho Power. For information relating to IDACORP's and Idaho Power's computation of income tax expense and estimated annual effective tax rate, see Note 2 - “Income Taxes” to the condensed consolidated financial statements included in this report.

Accelerated Amortization of ADITC: Idaho Power's December 2011 settlement stipulation with the IPUC and other parties provided for the availability of additional amortization of ADITC if Idaho Power's actual Idaho ROE is below 9.5 percent in any calendar year from 2012 to 2014.  For information relating to Idaho Power's 2011 settlement stipulation, see Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report. In accordance with the settlement stipulation, Idaho Power has $25 million of additional ADITC amortization available for use in 2012. Based on its estimate of full year Idaho ROE, Idaho Power has no additional ADITC amortization recorded for the nine months ended

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September 30, 2012. As of the date of this report, Idaho Power does not expect to record additional ADITC amortization for full year 2012.

Bonus Depreciation: Bonus depreciation provides for the accelerated deduction of current capital expenditures from certain asset classes.  For 2012, the deduction is equal to 50 percent of a qualifying asset's cost. Idaho Power has included an estimated bonus depreciation deduction in its current federal income tax provision.

LIQUIDITY AND CAPITAL RESOURCES

Overview

IDACORP's and Idaho Power's operating cash flows are driven principally by Idaho Power's sales of electricity and transmission capacity.  Significant uses of cash flows from operations include the purchase of fuel and power, other operating expenses, capital expenditures, pension plan contributions, and interest. Operating cash flows can be significantly influenced by factors such as weather conditions, rates and the outcome of regulatory proceedings, and economic conditions. As fuel and purchased power are significant uses of cash, and at the same time the prices can be volatile and difficult to predict, Idaho Power has regulatory mechanisms in place that provide for the deferral and recovery of the majority of the fluctuation in those costs. However, if actual costs rise above the level allowed in retail rates, deferral balances increase (reflected as a regulatory asset), negatively affecting operating cash flows until such time as these costs, with interest, are recovered from customers.

Idaho Power uses operating and capital budgets to control operating costs and optimize capital expenditures, and funds its liquidity needs for capital expenditures through cash flows from operations, debt offerings, commercial paper markets, credit facilities, and capital contributions from IDACORP.  Idaho Power periodically files for rate adjustments to recover increased operating costs and capital investments to provide the opportunity to align Idaho Power's earned returns with those allowed by regulators. Idaho Power is in a period of significant infrastructure investment, adding capacity to its baseload generation, transmission system, and distribution facilities in an effort to ensure an adequate supply of electricity, to provide service to new customers, and to maintain system reliability.  Idaho Power's hydroelectric and thermal generation facilities require continuing upgrades and component replacement, and the costs related to relicensing hydroelectric facilities and complying with the new licenses are substantial.  As a result of these and other projects, Idaho Power estimates that total capital expenditures will be between $720 million and $735 million over the period from 2012 (inclusive of amounts incurred year-to-date in 2012) through 2014.

As of October 26, 2012, IDACORP's and Idaho Power's access to debt, equity, and credit arrangements included:

• their respective $125 million and $300 million revolving credit facilities;

• IDACORP's shelf registration statement, which it may use for the issuance of debt securities and common stock, including up to 3.0 million shares of IDACORP common stock available for issuance under its continuous equity program. Approximately $539 million of debt and equity securities issuances remained available under the shelf registration statement;

• Idaho Power's shelf registration statement, which it may use for the issuance of first mortgage bonds and debt securities; $150 million remained available under the shelf registration statement, which expires in May 2013; and

• IDACORP's and Idaho Power's issuance of commercial paper, which may be issued up to an amount equal to the available capacity under their respective credit facilities, and is used to meet short-term liquidity requirements.

IDACORP and Idaho Power expect to continue financing capital requirements during 2012 and into 2013 with a combination of internally generated funds and externally financed capital, and believe that access to their credit facilities and operating cash flows generated by Idaho Power's utility business are sufficient to meet short-term obligations. To meet long-term maturing debt obligations and costs of infrastructure development, such as Idaho Power's 500-kV transmission projects, the companies may use a combination of internally generated funds, credit facilities, the issuance of long-term debt or equity and, in the case of Idaho Power, capital contributions from IDACORP. Should economic or financing conditions deteriorate, the companies may be required to defer or eliminate certain capital expenditures, to the extent it can do so while maintaining the reliability of its system and service and timely complying with environmental and regulatory obligations. The conditions of the capital markets and the weak economy have in recent years caused a general concern regarding access to sufficient capital at a reasonable cost.  Notwithstanding this concern, IDACORP and Idaho Power have not been significantly affected by this disruption in the credit environment, including in the commercial paper markets, and currently expect to continue to be able to access the capital markets to meet anticipated short- and long-term borrowing needs.

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Idaho Power issued $150 million of first mortgage bonds, medium-term notes in April 2012, using a portion of the net proceeds to redeem prior to maturity $100 million of first mortgage bonds, medium-term notes due November 2012. IDACORP and Idaho Power have no other debt maturities in 2012 and expect a minimal need for any additional external financing in 2012, other than issuances of commercial paper to meet cash balancing needs from time-to-time. Idaho Power has $70 million of first mortgage bonds, medium-term notes, due in October 2013, with no first mortgage bonds due thereafter until 2018.

During the first half of 2012, IDACORP continued to issue common stock under the pre-existing dividend reinvestment and employee-related stock purchase plans. Effective July 1, 2012, IDACORP discontinued original issuances of common stock and instructed the plan administrators to use market purchases of IDACORP common stock for purposes of acquiring IDACORP common stock for the IDACORP, Inc. Dividend Reinvestment and Stock Purchase Plan and the Idaho Power Company Employee Savings Plan. However, IDACORP may determine at any time to resume original issuances of common stock under those plans. IDACORP may also determine to issue common stock from time-to-time under its continuous equity program, depending on market conditions and capital needs. IDACORP and Idaho Power seek to maintain capital structures of approximately 50 percent debt and 50 percent equity, and maintaining this ratio influences IDACORP's and Idaho Power's debt and equity issuance decisions. As of September 30, 2012, IDACORP's and Idaho Power's capital structures were as follows:

	IDACORP	Idaho Power
Debt	47%	49%
Equity	53%	51%

Operating Cash Flows

IDACORP’s and Idaho Power’s operating cash inflows for the nine months endedSeptember 30, 2012 were $181 million and $176 million, respectively.  IDACORP's and Idaho Power's operating cash flows decreased by $53 million and $50 million, respectively, compared to the nine months endedSeptember 30, 2011.  With the exception of cash flows related to income taxes, IDACORP’s operating cash flows are principally derived from the operating cash flows of Idaho Power.  Significant items that affected the companies' operating cash flows in the first nine months of 2012 relative to the same period in 2011 were as follows:

• Idaho Power made contributions of $44.3 million to its defined benefit pension plan during the first nine months of 2012, while it made $18.5 million of cash contributions during the first nine months of 2011;

•      cash outflows related to income taxes increased by $13 million and $8 million for IDACORP and Idaho Power, respectively. IDACORP had net income tax payments of $1 million in 2012 compared with net refunds of nearly $12 million in 2011. Idaho Power’s net payments to IDACORP for income tax were $1 million for the nine months endedSeptember 30, 2012, compared with net refunds of $7 million for the same period in 2011;

• changes in regulatory assets associated with the Idaho and Oregon PCA mechanisms reduced cash flows by $74 million, as Idaho Power collected $20 million less of previously deferred costs and incurred $54 million less in the current year accrual, as compared with the first nine months of 2011; and

• the company's investment in BCC resulted in a net distribution to Idaho Power of $12 million for the first nine months of 2012, as compared to a net distribution of $1 million for the first nine months of 2011. The change in net distribution from year to year is the result of increased net income at BCC and the impact of timing differences associated with BCC incurring costs for reclamation activities and the reimbursement of those costs from the established reclamation trust fund.

Investing Cash Flows

Cash flows from investing activities consist primarily of capital expenditures related to new construction and improvements to Idaho Power’s generation, transmission, and distribution facilities.  IDACORP’s and Idaho Power’s investing cash outflows for the nine months endedSeptember 30, 2012 were $185 million, a decrease of $75 million compared to the nine months endedSeptember 30, 2011.  Investing cash outflows for 2012 and 2011 were primarily for construction of utility infrastructure needed to address Idaho Power’s peak demand growth, aging plant and equipment, and forecasted customer growth. The expenditures during the first nine months of 2012 for additions to property, plant, and equipment were less than the same period in 2011, largely as a result of reduced activity related to the Langley Gulch power plant, as the plant became commercially available on June 29, 2012.

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Financing Cash Flows

Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed.  Idaho Power funds liquidity needs for capital investment, working capital, energy and price hedging, and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets, and credit facilities.  IDACORP funds its cash requirements, such as payment of taxes, capital contributions to Idaho Power, and non-utility expenses allocated to IDACORP, through cash flows from operations, commercial paper markets, sales of common stock, and credit facilities.

IDACORP’s financing cash outflows for the nine months endedSeptember 30, 2012 were $4 million and Idaho Power’s financing cash inflows were $3 million for the same period.  The following are significant items that affected financing cash flows in the first nine months of 2012:

• in May 2012, Idaho Power redeemed prior to maturity $100 million of outstanding first mortgage bonds due November 2012 using a portion of the proceeds from the $150 million of first mortgage bonds issued in April 2012;

•      IDACORP and Idaho Power paid cash dividends of approximately $50 million; and

•      IDACORP made a capital contribution of $7.5 million to Idaho Power.

On June 17, 2010, Idaho Power entered into a Selling Agency Agreement with Banc of America Securities LLC; BNY Mellon Capital Markets, LLC; J.P. Morgan Securities Inc.; KeyBanc Capital Markets Inc.; Merrill Lynch, Pierce, Fenner & Smith Incorporated; Mitsubishi UFJ Securities (USA), Inc.; RBC Capital Markets Corporation; SunTrust Robinson Humphrey, Inc.; U.S. Bancorp Investments, Inc.; and Wells Fargo Securities, LLC in connection with the potential issuance and sale from time to time of up to $500 million aggregate principal amount of first mortgage bonds under a shelf registration statement. In August 2010, Idaho Power issued $200 million of first mortgage bonds, medium-term notes, Series I, under the shelf registration statement. On April 13, 2012, Idaho Power issued $75 million of 2.95% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2022 and $75 million of 4.30% first mortgage bonds, medium-term notes, Series I, maturing on April 1, 2042, under the Selling Agency Agreement and shelf registration statement. In April 2012, Idaho Power issued an irrevocable notice of redemption to redeem, prior to maturity, its $100 million in principal amount of 4.75% first mortgage bonds, medium-term notes due November 2012. In May 2012, Idaho Power used a portion of the net proceeds of the April 2012 issuance of first mortgage bonds, medium-term notes to effect the redemption.

Financing Programs

Shelf Registrations: IDACORP has an effective registration statement that, as of the date of this report, can be used for the issuance of up to $539 million of debt securities and common stock. Idaho Power has an effective registration statement that, as of the date of this report, can be used for the issuance of up to $150 million of first mortgage bonds and unsecured debt. Refer to Note 4 - “Long-Term Debt” to the condensed consolidated financial statements included in this report for more information regarding long-term financing arrangements.

The issuance of first mortgage bonds requires that Idaho Power meet interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. Future issuances of first mortgage bonds are subject to satisfaction of covenants and security provisions set forth in the Indenture of Mortgage and Deed of Trust, market conditions, regulatory authorizations, and covenants contained in other financing agreements. The Indenture of Mortgage and Deed of Trust limits the amount of additional first mortgage bonds that Idaho Power may issue to the sum of (a) the principal amount of retired first mortgage bonds and (b) 60 percent of total unfunded property additions, as defined in the Indenture of Mortgage and Deed of Trust. As of September 30, 2012, Idaho Power could issue approximately $1.3 billion of additional first mortgage bonds based on retired first mortgage bonds and total unfunded property additions. However, the Indenture of Mortgage and Deed of Trust further limits the maximum amount of first mortgage bonds at any one time outstanding to $2.0 billion, and as a result the maximum amount of first mortgage bonds Idaho Power could issue as of September 30, 2012 was limited to approximately $489 million. Idaho Power may increase the $2.0 billion limit on the maximum amount of first mortgage bonds outstanding by filing a supplemental indenture with the trustee as provided in the Indenture of Mortgage and Deed of Trust.

Credit Facilities: IDACORP and Idaho Power have $125 million and $300 million credit facilities, respectively. Each of the credit facilities may be used for general corporate purposes and commercial paper back-up. IDACORP's facility permits borrowings under a revolving line of credit of up to $125 million at any one time outstanding, including swingline loans not to exceed $15 million at any time and letters of credit not to exceed $50 million at any time. IDACORP's facility may be increased, subject to specified conditions, to $150 million. Idaho Power's facility permits borrowings through the issuance of loans and standby letters of credit of up to $300 million at any one time outstanding, including swingline loans not to exceed

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$30 million at any one time. Idaho Power's facility may be increased, subject to specified conditions, to $450 million. The interest rates for any borrowings under the facilities are based on either (1) a floating rate that is equal to the highest of the prime rate, federal funds rate plus 0.5 percent, or LIBOR rate plus 1.0 percent, or (2) the LIBOR rate, plus, in each case, an applicable margin. The applicable margin is based on IDACORP's or Idaho Power's, as applicable, senior unsecured long-term indebtedness credit rating by Moody's Investors Service, Inc., Standard and Poor's Ratings Services, and Fitch Rating Services, Inc., as set forth on a schedule to the credit agreements. The companies also pay a facility fee based on the respective company's credit rating for senior unsecured long-term debt securities.

Each facility contains a covenant requiring each company to maintain a leverage ratio of consolidated indebtedness to consolidated total capitalization equal to or less than 65 percent as of the end of each fiscal quarter. In determining the leverage ratio, “consolidated indebtedness” broadly includes all indebtedness of the respective borrower and its subsidiaries, including, in some instances, indebtedness evidenced by certain hybrid securities (as defined in the credit agreement). “Consolidated total capitalization” is calculated as the sum of all consolidated indebtedness, consolidated stockholders' equity of the borrower and its subsidiaries, and the aggregate value of outstanding hybrid securities. At September 30, 2012, the leverage ratios for IDACORP and Idaho Power were 47 percent and 49 percent, respectively. IDACORP's and Idaho Power's ability to utilize the credit facilities is conditioned upon their continued compliance with the leverage ratio covenants included in the credit facilities, which could limit the ability of the companies to issue first mortgage bonds and debt securities. There are additional covenants, subject to exceptions, that prohibit certain mergers, acquisitions, and investments, restrict the creation of certain liens, and prohibit entering into any agreements restricting dividend payments from any material subsidiary. At September 30, 2012, IDACORP and Idaho Power were in compliance with all facility covenants. Further, IDACORP and Idaho Power do not believe they will be in violation or breach of its significant debt covenants during the remainder of 2012, but were circumstances to arise that may alter that view management would take appropriate action to mitigate any such issue.

The events of default under both facilities include, without limitation, non-payment of principal, interest, or fees; materially false representations or warranties; breach of covenants; bankruptcy or insolvency events; condemnation of property; cross-default to certain other indebtedness; failure to pay certain judgments; change of control; failure of IDACORP to own free and clear of liens the voting stock of Idaho Power; the occurrence of specified events or the incurring of specified liabilities relating to benefit plans; and the incurrence of certain environmental liabilities, subject, in certain instances, to cure periods.

Upon any event of default relating to the voluntary or involuntary bankruptcy of IDACORP or Idaho Power or the appointment of a receiver, the obligations of the lenders to make loans under the applicable facility and to issue letters of credit will automatically terminate and all unpaid obligations will become due and payable. Upon any other event of default, the lenders holding greater than 50 percent of the outstanding loans or greater than 50 percent of the aggregate commitments (required lenders) or the administrative agent with the consent of the required lenders may terminate or suspend the obligations of the lenders to make loans under the facility and to issue letters of credit under the facility and/or declare the obligations to be due and payable. During an event of default under the facilities, the lenders may, at their option, increase the applicable interest rates then in effect and the letter of credit fee by 2.0 percentage points per annum. A ratings downgrade would result in an increase in the cost of borrowing, but would not result in a default or acceleration of the debt under the facilities. However, if Idaho Power's ratings are downgraded below investment grade, Idaho Power must extend or renew its authority for borrowings under its IPUC and OPUC regulatory orders.

While the credit facilities provide for an original maturity date of October 26, 2016, the credit agreements grant IDACORP and Idaho Power the right to request up to two one-year extensions, in each case subject to certain conditions. On October 12, 2012, IDACORP and Idaho Power executed First Extension Agreements with each of the lenders, extending the maturity date under both agreements to October 26, 2017. No other terms of the credit agreements, including the amount of permitted borrowings under the credit agreements, were affected by the extension.

Without additional approval from the IPUC, the OPUC, and the Public Service Commission of Wyoming, the aggregate amount of short-term borrowings by Idaho Power at any one time outstanding may not exceed $450 million.

Commercial Paper: IDACORP and Idaho Power have commercial paper programs under which they may issue unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time not to exceed the available capacity under their respective credit facilities, described above. IDACORP's and Idaho Power's credit facilities are available to the companies to support borrowings under their commercial paper programs. The commercial paper issuances are used to provide an additional financing source for the companies' short-term liquidity needs. The maturities of the commercial paper issuances will vary, but may not exceed 270 days from the date of issue. Individual instruments carry a fixed rate during their respective terms, although the interest rates are reflective of current market conditions, subjecting the companies to fluctuations in interest rates.

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Available Short-Term Liquidity: The table below outlines available short-term borrowing liquidity as of the dates specified.

	September 30, 2012						December 31, 2011
	IDACORP(2)			Idaho Power			IDACORP(2)			Idaho Power
Revolving credit facility	$	125,000		$	300,000		$	125,000		$	300,000
Commercial paper outstanding	(51,400		)	—			(54,200		)	—
Identified for other use (1)	—			(24,245		)	—			(24,245		)
Net balance available	$	73,600		$	275,755		$	70,800		$	275,755
(1)  Port of Morrow and American Falls bonds that Idaho Power could be required to purchase prior to maturity under the optional or mandatory purchase provisions of the bonds, if the remarketing agent for the bonds is unable to sell the bonds to third parties.
(2)  Holding company only.

At October 26, 2012, IDACORP had no loans outstanding under its credit facility and $70 million of commercial paper outstanding, and Idaho Power hadno loans outstanding under its credit facility and no commercial paper outstanding. The table below presents additional information about short-term commercial paper borrowing during the three- and nine-month periods ended September 30, 2012.

	Three months ended						Nine months ended
	September 30, 2012						September 30, 2012
	IDACORP (1)			Idaho Power			IDACORP (1)			Idaho Power
Commercial paper:
Period end:
Amount outstanding	$	51,400		$	—		$	51,400		$	—
Weighted average interest rate	0.47		%	—		%	0.47		%	—		%
Daily average amount outstanding during the period	$	52,543		$	9,500		$	54,342		$	4,835
Weighted average interest rate during the period	0.48		%	0.48		%	0.47		%	0.47		%
Maximum month-end balance	$	52,000		$	12,000		$	61,500		$	12,000
(1) Holding company only

Impact of Credit Ratings on Liquidity and Collateral Obligations

IDACORP’s and Idaho Power’s access to capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on their respective credit ratings.  The table below outlines the ratings of Idaho Power’s and IDACORP’s securities, and the ratings outlook, by Standard & Poor’s Ratings Services and Moody’s Investors Service as of the date of this report.

	S&P		Moody’s
	Idaho Power	IDACORP	Idaho Power	IDACORP
Corporate Credit Rating/Long-Term Issuer Rating	BBB	BBB	Baa 1	Baa 2
Senior Secured Debt	A-	None	A2	None
Senior Unsecured Debt	BBB	None	Baa 1	None
Short-Term Tax-Exempt Debt	BBB/A-2	None	Baa 1/ VMIG-2	None
Commercial Paper	A-2	A-2	P-2	P-2
Senior Unsecured Credit Facility	None	None	Baa 1	Baa 2
Rating Outlook	Stable	Stable	Stable	Stable

These security ratings reflect the views of the ratings agencies.  An explanation of the significance of these ratings may be obtained from each rating agency.  Such ratings are not a recommendation to buy, sell, or hold securities.  Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change.  Each rating agency has its own methodology for assigning ratings and, accordingly, each rating should be evaluated independently of any other rating.

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Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties.  As of September 30, 2012, Idaho Power had posted $1 million of performance assurance collateral.  Should Idaho Power experience a reduction in its credit rating on its unsecured debt to below investment grade Idaho Power could be subject to requests by its wholesale counterparties to post additional performance assurance collateral, and counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions.  Based upon Idaho Power’s current energy and fuel portfolio and market conditions as of September 30, 2012, the amount of additional collateral that could be requested upon a downgrade to below investment grade is approximately $4.5 million.  To minimize capital requirements, Idaho Power actively monitors its portfolio exposure and the potential exposure to additional requests for performance assurance collateral through sensitivity analysis.

Capital Requirements

Idaho Power's construction expenditureswere $188 million and $267 million during the nine months endedSeptember 30, 2012 and 2011, respectively.  The table below presents Idaho Power's estimated cash requirements for construction, excluding AFUDC, for 2012 (including amounts incurred to date during 2012) through 2014 (in millions of dollars).

	2012	2013-2014
Ongoing capital expenditures	$200-205	$490-500
Langley Gulch Power Plant (detailed below)	30	—
Total	$230-235	$490-500

Major Infrastructure Projects:

Idaho Power is engaged in the development of a number of significant projects and has entered into arrangements with third parties concerning joint infrastructure development. The discussion below provides a summary of certain of these projects and notable developments since the discussion of these matters included in Part II, Item 7 - “MD&A - Capital Requirements” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011. The discussion below should be read in conjunction with that report.

Langley Gulch Power Plant: The Langley Gulch power plant is a natural gas-fired combined cycle combustion turbine generating plant with a summer nameplate capacity of approximately 300 MW and a winter capacity of approximately 330 MW. Idaho Power placed the plant in service on June 29, 2012. Idaho Power incurred $396 million, including AFUDC, of capital expenditures associated with the project from inception in 2009 through September 2012.

Boardman-to-Hemingway Line:The Boardman-to-Hemingway line, a proposed 300-mile, 500-kV transmission project between a station near Boardman, Oregon and the Hemingway station near Boise, Idaho, would provide transmission service to meet needs identified in the 2011 Integrated Resource Plan (IRP). In January 2012, Idaho Power entered into a joint funding agreement with PacifiCorp and the Bonneville Power Administration (BPA) to jointly pursue permitting of the project. The joint funding agreement provides that Idaho Power's interest in the permitting phase of the project would be approximately 21 percent, and that during future negotiations relating to construction of the transmission line Idaho Power would seek to retain that percentage interest in the completed project. Idaho Power's estimated share of the cost of the permitting phase of the project is $13 million, including AFUDC. Total cost estimates for the project are between approximately $890 million and $940 million, including AFUDC. This cost estimate excludes the impacts of inflation and price changes of materials and labor resources that may occur following the date of the estimate. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs beyond the permitting phase are not included in the table above.

Federal and state permitting continues to move forward with a draft environmental impact statement (EIS) expected to be issued in the first half of 2013. The completion date of the project is subject to siting, permitting, regulatory approvals, in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other conditions. Based on Idaho Power's assessment of those and other factors, as of the date of this report Idaho Power estimates that a project in-service date prior to 2018 is unlikely. Idaho Power will evaluate the impact of the new in-service date estimate in its 2013 IRP and determine if Idaho Power needs to take additional actions to ensure that it reliably meets load service obligations.

On October 2, 2012, the BPA issued a statement that it had completed an initial prioritization of potential service arrangements for its customer load in southeastern Idaho and, while it had not made a final decision on options for this service, the BPA

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identified the Boardman-to-Hemingway line with a transmission asset swap as a top priority for pursuit during 2013 and beyond.  According to the BPA, of the options it evaluated, the Boardman-to-Hemingway line with a transmission asset swap has the potential to keep the BPA's costs low, relative to the other options considered.

Gateway West Line: Idaho Power and PacifiCorp are pursuing the joint development of the Gateway West project, a 500-kV transmission project between a station located near Douglas, Wyoming and the Hemingway station. In January 2012, Idaho Power and PacifiCorp entered a new joint funding agreement for permitting of the project. Idaho Power's estimated cost for the permitting phase of the Gateway West project is approximately $24 million, including AFUDC. As of the date of this report, Idaho Power estimates the total cost for its share of the project (including both permitting and construction) to be between $150 million and $300 million, including AFUDC. Idaho Power's share of the permitting phase of the project (excluding AFUDC) is included in the capital requirements table above. Construction costs are not included in the table above. Timing of the construction of each segment of the project is subject to siting, permitting, regulatory approvals, in-service date requirements of the parties electing to construct the line, the terms of any resulting joint construction agreements, and other conditions. On October 4, 2012, the U.S. Bureau of Land Management (BLM) released its preferred route for the project, and Idaho Power is reviewing the implications of that route, including the potential impact on project costs. Idaho Power anticipates continued engagement with stakeholders as the route is evaluated.  The BLM's schedule provides for the issuance of a final EIS in the fourth quarter of 2012 and a record of decision in mid-2013.

Memorandum of Understanding, dated January 12, 2012, among Idaho Power, PacifiCorp, and BPA (2012 MOU): Executed in connection with the BPA's participation in the joint funding agreement for the Boardman-to-Hemingway line, the 2012 MOU provides that the parties will negotiate in good faith the terms of mutually satisfactory definitive agreements that would allow BPA to meet its load service obligations in southeast Idaho. It provides that the parties will explore opportunities to establish eastern Idaho load service from the Hemingway substation in exchange for similar service from the Federal Columbia River Transmission System. The 2012 MOU outlines at least two potential alternatives for further negotiation, including a network service option and an asset ownership rights option on the parties' transmission systems, both of which include BPA participation in the Boardman-to-Hemingway transmission line. Any party may terminate the 2012 MOU at any time, without penalty, and the 2012 MOU automatically expires on December 31, 2014.

AMI/Smart Grid and American Recovery and Reinvestment Act of 2009 (ARRA): The advanced metering infrastructure project provides the means to automatically retrieve energy consumption information, eliminating manual meter reading expense. In December 2011, Idaho Power completed the installation of its advanced metering technology at a cost of $71.8 million. Under the ARRA, Idaho Power was awarded a grant of $47 million from the DOE. The grant was signed by the DOE in April 2010 and applies to project costs, including those associated with the AMI project, incurred beginning in August 2009 for a three-year term. As of September 30, 2012, Idaho Power had invoiced approximately $39.1 million to the DOE, of which $37.5 million had been received. The costs to be reimbursed by the grant are not included in the Capital Requirements table above.

Changes to Capital Project Mix: At times, Idaho Power may seek to accelerate, scale back, modify, or eliminate projects, or seek alternative projects, to accommodate anticipated resource needs and to help ensure its ability to provide reliable electric service and meet load and transmission capacity obligations. Scaling back or eliminating a project due to regulatory challenges or other factors influencing the feasibility of a project may result in Idaho Power pursuing one or more separate, more costly projects. For instance, if Idaho Power were unable to secure permits or joint funding commitments to develop transmission infrastructure necessary to serve loads, it may terminate those projects and, as an alternative, develop additional generation facilities within areas where Idaho Power has available transmission capacity. Idaho Power's IRP seeks to address these potential alternatives and their associated risks and costs. Termination of a project carries with it the potential for a write-off of all or a significant portion of the costs associated with the project.

Defined Benefit Pension Plan Contribution:During the first nine months of 2012, Idaho Power contributed $44.3 million to its defined benefit pension plan. Idaho Power contributed $18.5 million to its defined benefit pension plan in 2011 and $60 million in 2010. As reported in more detail in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, Idaho Power expects to make additional significant cash contributions to its defined benefit pension plan in coming years. Idaho Power has evaluated the potential impact of recently approved federal legislation that will alter the timing and amount of future contributions to the defined benefit pension plan. The legislation, signed into law in July 2012, provides a smoothing mechanism applicable to the calculation of plan minimum contributions, and will reduce minimum amounts required to be contributed to the plan in at least the next few years. The legislation's partial funding relief is automatically effective for all contributions beginning in 2013, and Idaho Power chose to adopt the funding relief for its 2012 contributions. In May 2011, the IPUC authorized Idaho Power to increase its annual recovery and amortization of deferred pension costs from $5.4 million to $17.1 million. The primary impact of pension contributions is on cash flows.

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Contractual Obligations

IDACORP's and Idaho Power's contractual obligations, outside of the ordinary course of business, have not changed materially from the amounts disclosed in their Annual Report on Form 10-K for the year ended December 31, 2011, except as follows:

• nine power purchase agreements were terminated due to either an uncured breach by the respective counterparties or pursuant to IPUC-approved settlement arrangements between the parties, which reduced Idaho Power's contractual payment obligations by approximately $736 million over the 15-year to 25-year lives of the contracts; and

• Idaho Power issued $150 million of first mortgage bonds, medium-term notes (long-term indebtedness), using a portion of the net proceeds from that issuance to redeem prior to maturity $100 million of outstanding first mortgage bonds, medium-term notes due November 2012.

Dividends

The amount and timing of dividends paid on IDACORP’s common stock are within the discretion of IDACORP’s board of directors.  IDACORP's board of directors reviews the dividend rate periodically to determine its appropriateness in light of IDACORP’s current and long-term financial position and results of operations, capital requirements, rating agency requirements, contractual and regulatory restrictions, legislative and regulatory developments affecting the electric utility industry in general and Idaho Power in particular, competitive conditions, and any other factors the board of directors deems relevant.  The ability of IDACORP to pay dividends on its common stock is dependent upon dividends paid to it by its subsidiaries, primarily Idaho Power. IDACORP has a dividend policy that provides for a target long-term dividend payout ratio of between 50 and 60 percent of sustainable IDACORP earnings, with the flexibility to achieve that payout ratio over time and to adjust the payout ratio or to deviate from the target payout ratio from time to time based on the various factors that drive the IDACORP board of directors' dividend decisions. Notwithstanding the dividend policy adopted by the IDACORP board of directors, the dividends IDACORP pays remain in the discretion of the board of directors who, when evaluating the dividend amount, will continue to take into account the foregoing factors, among others.

On January 19, 2012, IDACORP's board of directors voted to increase the quarterly dividend, commencing with the dividend paid on February 29, 2012, to $0.33 per share of IDACORP common stock, from the prior quarterly dividend amount of $0.30 per share of IDACORP common stock. On September 20, 2012, IDACORP's board of directors voted to increase the quarterly dividend again in 2012, commencing with the dividend payable on November 30, 2012, to $0.38 per share of IDACORP common stock. In its September 20 press release, IDACORP stated that based on IDACORP’s then-current estimates for earnings and cash flow and assuming IDACORP meets those estimates, IDACORP’s management anticipates recommending to the board of directors an additional increase to the quarterly dividend in September 2013 of at least ten percent. As of the date of this report, IDACORP's management's expectations for a September 2013 dividend increase recommendation have not changed.

For additional information relating to IDACORP and Idaho Power dividends, including additional restrictions on IDACORP’s and Idaho Power’s payment of dividends, see Note 6 – “Common Stock” to the condensed consolidated financial statements included in this report.

Contingencies and Proceedings

IDACORP and Idaho Power are involved in a number of litigation, alternative dispute resolution, and administrative proceedings, and are subject to claims and legal actions arising in the ordinary course of business, that could affect their future results of operations and financial condition. Certain legal or administrative proceedings to which IDACORP or Idaho Power are parties or are otherwise involved, and certain actual or potential legal claims pertaining to Idaho Power, are described in Note 9 - "Contingencies" to the condensed consolidated financial statements included in this report. Except where noted in Note 9, in many instances IDACORP and Idaho Power are unable to predict the outcomes of the matters or estimate the impact the proceedings may have on their financial positions, results of operations, or cash flows.

Idaho Power is also actively monitoring various environmental regulations that may have a significant impact on its future operations. Given uncertainties regarding the outcome, timing, and compliance plans for these environmental matters, Idaho Power is unable to determine the financial impact of these regulations, but does believe that future capital investment for infrastructure and modifications to its electric generating facilities to comply with these regulations could be significant.

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Off-Balance Sheet Arrangements

IDACORP’s and Idaho Power's off-balance sheet arrangements have not changed materially from those reported in MD&A in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Impact of the Dodd-Frank Wall Street Reform and Consumer Protection Act

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted into law in July 2010. The Dodd-Frank Act establishes regulatory jurisdiction by the Commodity Futures Trading Commission (CFTC) and the SEC for certain swaps (which include a variety of derivative instruments) and the users of such swaps, and directed the CFTC and SEC to promulgate rules implementing a number of provisions of the Dodd-Frank Act. Under rules adopted pursuant to the Dodd-Frank Act, entities designated as "swap dealers" or "major swap participants" are subject to specified margin, collateral, mandatory exchange clearing, and reporting obligations. In April 2012, the SEC and the CFTC issued a joint final rule defining the terms "swap dealer" and "major swap participant." Idaho Power has determined that it is unlikely to be classified as either a swap dealer or a major swap participant under the rules, thus exempting Idaho Power from direct application of certain of the margin, collateral, and other burdensome and costly requirements of the rules. However, Idaho Power expects that entities classified as swap dealers or major swap participants will pass along their increased costs through higher prices and reductions in thresholds for posting collateral. Further, while Idaho Power believes that it may often rely upon an exemption from mandatory exchange clearing obligations contained in the rules, Idaho Power expects that the cost of entering into non-cleared swaps may increase and that required margin levels may be higher. Idaho Power will also incur costs in connection with the reporting obligation under the rules. As of the date of this report Idaho Power expects that the financial and operational impact of the swap-related provisions of the Dodd-Frank Act and the CFTC's and SEC's associated rules will not be significant.

REGULATORY MATTERS

Introduction

As a regulated utility, many of Idaho Power's fundamental business decisions are subject to the approval of governmental agencies. Idaho Power is under the retail jurisdiction (as to rates, service, accounting, and other general matters of utility operation) of the IPUC and the OPUC, which determine the rates that Idaho Power charges to its general business customers.  Idaho Power is also under the regulatory jurisdiction of the IPUC, the OPUC, and the Public Service Commission of Wyoming as to the issuance of debt and equity securities.  Also, as a public utility under the Federal Power Act, Idaho Power has authority to charge market-based rates for wholesale energy sales under its FERC tariff and to provide transmission services under its OATT.  Idaho Power uses general rate cases, cost adjustment mechanisms, and subject-specific filings to recover its costs of providing service and the costs of its energy efficiency and demand-side resources programs, seeking to earn a return on investment where permitted by regulators. Idaho Power remains focused on communicating with regulators the necessity of investments to better serve its customers, the prudence of the costs incurred, and the importance of a reasonable return on investment for IDACORP's shareholders.

Idaho Power's need for rate relief and the development of rate case plans takes into consideration short-term and long-term needs, as well as specific factors that can affect the timing of rate filings. Such factors include, among other things, in-service dates of major capital investments and the timing of changes in major revenue and expense items. Idaho Power filed general rate cases in Idaho and Oregon during 2011, as well as a single-issue rate case for the Langley Gulch power plant in Idaho and Oregon in 2012, which have largely concluded. Idaho Power will continue to assess its need for general rate relief in consideration of the factors described above. Between general rate cases, Idaho Power relies upon power cost adjustment mechanisms, riders, and other mechanisms to reduce regulatory lag, which refers to the period of time between making an investment or incurring an expense and earning a return and recovering that investment or expense. Management's focus on constructive regulatory outcomes in 2011 and 2012 has been targeted largely at eliminating that regulatory lag.

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Recent Regulatory Developments

In addition to the discussion below, which includes notable regulatory developments since the discussion of these matters in Item 7 - MD&A and in Note 3 - "Regulatory Matters" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011, refer to Note 3 - “Regulatory Matters” to the condensed consolidated financial statements included in this report for additional information and updates relating to Idaho Power's regulatory matters and recent regulatory filings and orders. The table below includes summary information on notable regulatory proceedings largely completed during 2012, and is followed by a summary of the more notable matters.

Description	Effective Date	Estimated Annual Rate Impact (millions)(1)
Idaho:
Langley Gulch power plant	7/1/2012	$	58.1
Power cost adjustment (2)	6/1/2012	43.0
2011 general rate case settlement	1/1/2012	34.0
Boardman power plant cost recovery	6/1/2012	1.5
Fixed cost adjustment (2)	6/1/2012	1.2
Revenue sharing pursuant to January 2010 settlement agreement (2)	6/1/2012	(27.1		)
Depreciation rate for non-AMI meters	6/1/2012	(10.6		)
Depreciation update (other than non-AMI meters and Boardman plant)	6/1/2012	(1.3		)
Oregon:
Langley Gulch power plant	10/1/2012	3.0
Oregon general rate case settlement	3/1/2012	1.8
Oregon annual power cost update (2)	6/1/2012	1.8

⁽¹⁾ The annual amount collected in rates is typically not recovered on a linear basis (i.e., 1/12th per month), and is instead recovered through Idaho Power's tiered rate structure, described above in this MD&A. Under a tiered rate structure, Idaho Power generally records revenues disproportionately during higher-load periods.

⁽²⁾  The $43.0 million rate increase for the Idaho power cost adjustment, $1.2 million rate increase for the fixed cost adjustment, and $27.1 million rate decrease resulting from revenue sharing pursuant to the January 2010 settlement agreement are applicable only for the period from June 1, 2012 to May 31, 2013. Similarly, a portion of the $1.8 million rate increase from the Oregon annual power cost update is applicable only for a one-year period.

Idaho General Rate Case Settlement: In December 2011, the IPUC approved a settlement stipulation in Idaho Power's general rate case, which provided for a 7.86 percent authorized rate of return on an Idaho-jurisdiction rate base of approximately $2.36 billion. The approved settlement stipulation resulted in a 4.07 percent, or $34.0 million, overall increase in Idaho Power's annual Idaho-jurisdictional base rate revenues. New rates in conformity with the settlement became effective on January 1, 2012.

Oregon General Rate Case Settlement: On February 23, 2012, the OPUC approved a settlement stipulation in Idaho Power's Oregon general rate case. The settlement stipulation provides for a $1.8 million base rate increase, a return on equity of 9.9 percent, and an overall rate of return of 7.757 percent in the Oregon jurisdiction. New rates in conformity with the settlement stipulation went into effect on March 1, 2012. The OPUC is conducting a second phase of the proceedings to address the prudence of Idaho Power's pollution control investments at the Jim Bridger coal-fired power plant.

ADITC and Revenue Sharing Mechanism: In December 2011, the IPUC issued an order, separate from the then-pending Idaho general rate case proceeding, approving a settlement stipulation that provides as follows:

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 is less than 9.5 percent, then Idaho Power may amortize additional ADITC to help achieve a minimum 9.5 percent Idaho ROE in the applicable year. Idaho Power would be permitted to amortize additional ADITC in an aggregate amount up to $45 million over the three-year period, but could use no more than $25 million in 2012;

• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.0 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.0 percent, and up to and including 10.5 percent, Idaho ROE for the applicable year would be shared equally between Idaho Power and its Idaho customers in the form of a rate reduction to become effective at the time of the subsequent year's PCA adjustment; and

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• if Idaho Power's actual Idaho ROE for 2012, 2013, or 2014 exceeds 10.5 percent, the amount of Idaho Power's Idaho- jurisdictional earnings exceeding a 10.5 percent Idaho ROE for the applicable year would be allocated 25 percent to Idaho Power and 75 percent to benefit Idaho customer rates through an offset in the pension balancing account, which would reduce the amount Idaho Power would collect from customers in rates.

The settlement stipulation provides that the Idaho ROE thresholds (9.5 percent, 10.0 percent, and 10.5 percent) will be automatically adjusted prospectively in the event the IPUC approves a change to Idaho Power's authorized return on equity as part of a general rate case proceeding seeking a rate change effective prior to January 1, 2015. As of the date of this report, Idaho Power does not anticipate the need to amortize additional ADITC in 2012.

Langley Gulch Power Plant: On June 29, 2012, the IPUC issued an order approving a $58.1 million increase in annual Idaho- jurisdiction base rates, effective July 1, 2012, for recovery of Idaho Power's investment in the Langley Gulch power plant and associated costs. On September 20, 2012, the OPUC issued an order approving an approximately $3.0 million increase in annual Oregon jurisdiction base rates for recovery of the investment and associated costs, with new rates in effect October 1, 2012. The plant became commercially available on June 29, 2012.

Power Cost Adjustment - Idaho: On April 13, 2012, Idaho Power made its annual PCA filing with the IPUC, requesting a $43 million increase to Idaho PCA rates, effective for the period from June 1, 2012 to May 31, 2013. The requested increase reflects increased projected power supply costs relative to the prior PCA year, due largely to an increase in mandated purchases of higher-cost, intermittent power under PURPA power purchase contracts. The IPUC issued an order on May 31, 2012 approving Idaho Power's application as filed. Previous annual PCA orders have resulted in a $40.4 million Idaho PCA rate decrease, effective June 1, 2011, and a $146.9 million Idaho PCA rate decrease, effective June 1, 2010. These prior PCA rate decreases were offset by increases in power supply costs in base rates and deferrals and amortization under the Idaho PCA mechanism, resulting in a relatively small impact on earnings.

Idaho Non-AMI Meter Depreciation:On April 27, 2012, the IPUC approved Idaho Power's February 2012 application requesting approval of a $10.6 million decrease in rates for specified customer classes, effective June 1, 2012, as a result of the removal of accelerated depreciation expense associated with non-AMI metering equipment.

Change in Deferred Net Power Supply Costs

Deferred power supply costs represent certain differences between Idaho Power's actual net power supply costs and the costs included in its retail rates, the latter being based on annual estimates of power supply costs. Deferred power supply costs are recorded on the balance sheets for future recovery or refund through customer rates. The table below summarizes the change in deferred net power supply costs during the nine months endedSeptember 30, 2012.

	Idaho			Oregon(1)			Total
Balance at December 31, 2011	$	(13,121	)	$	8,490		$	(4,631	)
Current period net power supply costs deferred	25,709			1,523			27,232
2011 revenue sharing liability applied to PCA true-up mechanism (2)	(27,201		)	—			(27,201		)
Prior amounts returned (recovered) through rates	21,993			(1,654		)	20,339
SO2 allowance and renewable energy certificate (REC) sales	(3,197		)	(156		)	(3,353		)
Interest and other	(243		)	511			268
Balance at September 30, 2012	$	3,940		$	8,714		$	12,654
(1)  Oregon power supply cost deferrals are subject to a statute that specifically limits rate amortizations of deferred costs to six percent of gross Oregon revenue per year (approximately $3 million).  Deferrals are amortized sequentially.
(2)  2011 revenue sharing includes a $27.1 million liability together with carrying charges.

PURPA Power Purchases - Challenges and Proceedings

Pursuant to the requirements of Section 210 of PURPA, the IPUC and OPUC have each issued orders and rules regulating Idaho Power's purchase of power from CSPP facilities.  A key component of the PURPA power purchase contracts is the energy price contained within the agreements.  Regulatory-mandated execution of PURPA agreements at times results in Idaho Power acquiring energy it does not need to serve loads, and at above wholesale market prices.  Substantially all PURPA power purchase costs are recovered through base rates and Idaho Power's power supply cost mechanisms, and thus the primary impact of the PURPA agreements is on customer rates.  In addition to increasing power purchase costs, integration of intermittent, non-dispatchable resources (such as wind power) into Idaho Power's portfolio creates a number of complex operational risks and challenges.

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Idaho Power remains engaged in proceedings at the IPUC and OPUC relating to the determination of appropriate power purchase prices and other terms of PURPA power purchase agreements. Idaho Power is also engaged in proceedings at the FERC relating to its obligations under PURPA power purchase agreements. On January 31, 2012, Idaho Power submitted written testimony in its PURPA proceedings before the IPUC, in support of its request that, among other items, the IPUC (a) change the methodology used to establish power purchase prices for PURPA projects, (b) reduce the maximum authorized PURPA power purchase agreement term from the existing 20 years to a maximum of 5 years, and (c) authorize a curtailment strategy that would allow Idaho Power to optimize use of its cost-effective resources. Separately, on March 12, 2012, Idaho Power filed an application with the IPUC seeking a temporary stay of its obligation to enter into new PURPA power purchase agreements. While the IPUC denied Idaho Power's request for a stay in a March 22, 2012 order, the IPUC's order provided that the PURPA pricing methodologies in effect as of that date do not produce rates that are just and reasonable or in the public interest. As a result, the IPUC's order further provided that the IPUC would individually evaluate all contracts for PURPA projects over 100 kW entered into by Idaho Power and presented to the IPUC for approval, noting that FERC regulations require that the purchase price be just and reasonable to customers and in the public interest. Hearings in the IPUC proceedings were held during August 2012. Similar proceedings at the OPUC are also ongoing.

Developments with Large Industrial Customer

In March 2009, the IPUC approved a September 2008 electric service agreement between Idaho Power and Hoku Materials, Inc. (Hoku), to provide electric service to Hoku’s polysilicon production facility then under construction in Idaho.  The initial term of the agreement was four years beginning December 1, 2009, with a maximum demand obligation during the initial term of 82 MW.  In connection with an overdue invoice for electric service, in February 2012 Idaho Power, Hoku, and the IPUC Staff filed with the IPUC a settlement stipulation to amend the electric service agreement, and on March 15, 2012, the IPUC approved the stipulation revising the contract.

As a result of Hoku's failure to remain timely in payments under the revised agreement, Idaho Power terminated its provision of electric service under the revised agreement in May 2012. Idaho Power applied a $2 million deposit to Hoku's April, May, and June 2012 invoices under the revised agreement and fully exhausted the deposit required by the revised agreement. For full year 2012 and prior to termination of service, Idaho Power had anticipated contract payments of $5.4 million that are unaffected by the PCA mechanism and $6.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $12.2 million. Assuming that Hoku does not perform its obligations under the revised agreement during the remainder of 2012, Idaho Power estimates that it will only recognize $3.8 million of full year 2012 revenues that are unaffected by the PCA mechanism and $2.8 million of revenues that are affected by and flow through the PCA mechanism, for a total of $6.6 million for full year 2012. The ultimate impact of non-payment and associated decreases in revenue on 2012 net income would be tempered by a decrease in costs Idaho Power may have incurred in connection with the provision of service to Hoku and the impact of the PCA mechanism, likely resulting in a relatively small impact on full year net income.

2011 Integrated Resource Plan - Oregon Acknowledgment

On May 21, 2012, the OPUC acknowledged Idaho Power's 2011 IRP, with conditions and exceptions. The OPUC directed Idaho Power to, among other things, include in its next IRP update an evaluation of environmental compliance costs for existing coal-fired plants. Idaho Power was directed to investigate whether there is "flexibility in the emerging environmental regulations" that would allow Idaho Power to "avoid early compliance costs by offering to shut down individual units prior to the end of their useful lives." The order also directed Idaho Power to conduct further plant-specific analysis to determine whether this trade-off would be in the ratepayers' interest. Idaho Power is currently preparing its 2013 IRP.

Hydroelectric Projects - Relicensing and Upgrades

Costs for the relicensing of Idaho Power's hydroelectric projects are recorded in construction work in progress until new multi-year licenses are issued by the FERC, at which time the charges are transferred to electric plant in service. Relicensing costs and costs related to new licenses will be submitted to regulators for recovery through the ratemaking process. HCC relicensing costs of $156 million were included in construction work in progress at September 30, 2012. As of the date of this report, the IPUC authorizes Idaho Power to include in its Idaho-jurisdiction rates approximately $6.5 million annually ($10.7 million grossed up for income taxes) of AFUDC relating to the HCC relicensing project, and collecting these amounts will reduce the relicensing amount submitted to regulators for recovery through the ratemaking process.

Item 7 - MD&A - "Regulatory Matters" in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011 contains a discussion of the status of relicensing efforts and other projects for the HCC, Swan Falls Project, and Shoshone Falls facility. Set forth below is an update on the status of those projects relative to that prior discussion.

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Swan Falls Project - On September 28, 2012, the FERC issued Idaho Power a 30-year license for continued operation of the Swan Falls hydroelectric project. Idaho Power is evaluating the terms and conditions of the license, but as of the date of this report believes that operational changes will be modest and that the capital investments it will be required to make under the terms of the license will be within the range Idaho Power expected.

Shoshone Falls Expansion - On July 1, 2010, the FERC amended the license for the Shoshone Falls project to expand its generating capacity from 12.5 MW to approximately 61 MW.  The amended license has an expiration date of 2034, but provides that the license will be extended to 2044 following completion of the proposed generation capacity expansion project.  On May 1, 2012, FERC granted Idaho Power a two-year schedule extension to complete construction of the expansion. As a result, the new deadline for construction completion is July 1, 2017. Subject to the outcome of additional cost studies and analysis and the results of further engineering and design work, Idaho Power will make a final determination whether to proceed with the expansion project. To mitigate the regulatory risk associated with the project, at least in part, Idaho Power plans to seek regulatory support for cost recovery from the IPUC and OPUC prior to commencement of construction.

ENVIRONMENTAL MATTERS

Overview

Idaho Power is subject to a broad range of federal, state, regional, and local laws and regulations designed to protect, restore, and enhance the environment.  Current and pending environmental legislation relates to, among other items, climate change, greenhouse gas emissions and air quality, renewable energy standards, mercury and other emissions, hazardous wastes, and polychlorinated biphenyls.  In addition to imposing continuing compliance obligations and associated costs, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief, and other sanctions. These laws and regulations are administered by the U.S. Environmental Protection Agency (EPA) and state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately need to be resolved by the courts. 

Additionally, the FERC licenses issued for Idaho Power's hydroelectric generating plants impose numerous environmental requirements, such as aeration of water discharged through turbines to meet dissolved gas and temperature standards in the tail waters downstream from the plants.  Idaho Power monitors these issues and reports the results to the appropriate regulatory agencies.  Also, Idaho Power co-owns three coal-fired power plants and owns three natural gas-fired combustion turbine power plants that are subject to a broad range of environmental requirements, including air quality regulation.  These regulations could affect IDACORP's and Idaho Power's results of operations and financial condition if the costs associated with these environmental requirements cannot be fully recovered in rates on a timely basis or at all.

Operation of Idaho Power's jointly-owned coal-fired power plants is subject to a broad range of federal, state, and local environmental laws and regulations, both pending and enacted. Idaho Power expects that these laws and regulations, which will continue to increase the cost of operating coal-fired power plants and constructing new facilities, will necessitate installation of additional pollution control devices at existing generating plants, or result in Idaho Power discontinuing operation of certain coal-fired plants where operation becomes uneconomical.  In connection with its IRP process, Idaho Power has been conducting cost studies and scenario analysis to assess these investment decisions, using a range of fuel pricing assumptions, plant upgrade and retirement costs, environmental regulation assumptions, replacement costs, and other factors in that assessment. Idaho Power plans to publish the results of its most recent analysis with its 2011 IRP update to be filed with the OPUC in November 2012, and invites interested parties to review and comment on the results of the analysis.

Included below is a summary of notable developments in environmental, climate change, sustainability, and related issues impacting Idaho Power since the discussion of these and other matters included in Part II, Item 7 - “MD&A - Environmental Issues” and “MD&A - Liquidity and Capital Resources - Capital Requirements - Environmental Regulation Costs” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Environmental Sustainability Initiatives

Extension of CO₂ Intensity Reduction Goal

While there is currently no national mandatory greenhouse gas reduction requirement, Idaho Power continues to prepare for potential legislative and/or regulatory restrictions on emissions in order to help reduce the costs of complying with such restrictions on its customers. To that end, Idaho Power is engaged in voluntary greenhouse gas emission intensity reduction efforts.  In September 2009, IDACORP's and Idaho Power's boards of directors approved guidelines that established a goal to

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reduce Idaho Power's resource portfolio's average CO₂ emission intensity for the 2010 through 2013 time period to a level of 10 to 15 percent below Idaho Power's 2005 CO₂ emission intensity of 1,194 lbs CO₂/MWh.  Idaho Power's estimated CO₂ emission intensity from its generation facilities, as submitted to the Carbon Disclosure Project, was 672, 1,051, and 1,004 lbs/MWh for 2011, 2010, and 2009 respectively.

As of the date of this report, Idaho Power is on-track to exceed the CO₂ emission intensity reduction goal it established in 2009. The combination of effective utilization of hydroelectric projects, above average stream flows during 2011, reduced usage of coal-fired facilities, and addition of the Langley Gulch natural gas-fired power plant have positioned the company to extend its CO₂ intensity reduction goal period for an additional two years, targeting an average reduction of 10 to 15 percent below its 2005 levels for the entire 2010 through 2015 time period. Idaho Power management plans to recommend to its board of directors that the board approve the extension of the intensity reduction goal.

Wind Integration Study

Since 2010, Idaho Power has seen an unprecedented increase in the number of wind power developments seeking to enter into power purchase arrangements with Idaho Power pursuant to PURPA. As of September 30, 2012, Idaho Power had CSPP wind contracts with on-line projects totaling 537 MW of nameplate capacity, as well as an additional 101 MW nameplate capacity from the Elkhorn Valley non-CSPP wind project.

As described above in this MD&A under “PURPA Power Purchases - Challenges and Proceedings,” Idaho Power has been involved in proceedings at the IPUC, OPUC, and FERC to determine the appropriate power purchase price and other terms of PURPA agreements, as to-date those terms have resulted in a significant increases in the number of PURPA projects seeking contracts with Idaho Power and associated escalation in power purchase costs to the detriment of Idaho Power's customers. Beyond the direct adverse impact on customer rates are the operational challenges imposed by power purchases mandated by PURPA. An abundance of wind power during times when Idaho Power has available lower-cost resources available to meet load demands has an impact on the operation of Idaho Power's other generation plants, system reliability, wear and tear on dispatchable generators from rapidly adjusting output to balance loads, and power supply costs. When forecast wind or other intermittent resources do not materialize, Idaho Power must have dispatchable resources on stand-by to ensure the continued delivery of reliable power. The quantity of wind generation that Idaho Power can integrate depends largely on customer load. During times of markedly low customer demand, the system of dispatchable generators often cannot provide the stand-by capacity for balancing wind without causing an over-generation condition. System hydro regulations, available reservoir storage volume, dispatched resources, FERC restrictions, environmental regulations, and numerous other conditions also influence Idaho Power's ability to integrate wind onto its system.

In response to the operational challenges associated with integrating wind, and the recognition that these challenges will become even more pronounced as the volume of intermittent resources in Idaho Power's portfolio increases, Idaho Power continues efforts to better understand the effects of wind on power system operation.  As part of these efforts, Idaho Power issued its first wind integration study in 2007, and beginning in 2011 Idaho Power launched its second, and more comprehensive, wind integration study.  The goal of the most recent study is to assess the costs incurred in modifying operations of dispatchable generating resources to allow them to respond to the variable and uncertain energy supplied by wind generators and deliver reliable energy to customers.  Additionally, the study aims to provide insight on the maximum amount of wind generation Idaho Power's system can accommodate without impacting reliability.  Idaho Power has committed considerable resources to the study, including working with an independent consultant, utility industry peers, and interested parties, and has also held public workshops.  Idaho Power intends to release the details of the report publicly and invites interested parties to provide their feedback. Further in response to the integration challenges, Idaho Power has implemented an internally developed wind forecasting system, in recognition that cost intensive modifications to operations intended to integrate wind are reduced, though not eliminated, with improved wind production forecasting.

As outlined in its inaugural sustainability report issued in May 2011, Idaho Power's goal is to maintain a balanced set of resources, including through its low-cost hydro, natural gas, and coal fleet, as well as through renewable energy and purchased power. In seeking this balance, Idaho Power does and will continue to take into consideration not only economic considerations, but also environmental concerns, including the impact of any dispatch and resource decisions on Idaho Power's carbon emission reduction goals.

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Environmental Regulation

Mercury and Air Toxics Standards (MATS): In April 2010, the U.S. District Court for the District of Columbia approved, by consent decree, a timetable that required the EPA to finalize a standard to control mercury emissions from coal-fired power plants by November 2011.  In March 2011, the EPA released the proposed MATS to control emissions of mercury and other hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units (EGUs) under the federal Clean Air Act (CAA). In the same notice, the EPA further proposed to revise the new source performance standards (NSPS) for fossil fuel-fired EGUs. Both the proposed HAPs regulation and the associated NSPS revisions were finalized on February 16, 2012. The regulation imposes maximum achievable control technology and NSPS on all coal-fired EGUs and replaces the former Clean Air Mercury Rule. Specifically, the regulation sets numeric emission limitations on coal-fired EGUs for total particulate matter (a surrogate for non-mercury HAPs), hydrogen chloride, and mercury. In addition, the regulation imposes a work practice standard for organic HAPs, including dioxins and furans. For the revised NSPS, for EGUs commencing construction of a new source after publication of the final rule, the EPA has established amended emission limitations for particulate matter, sulfur dioxide, and nitrogen oxides. Mercury continuous emission monitoring systems have been installed on all of the coal-fired units at the Jim Bridger, Boardman, and Valmy generating plants.  However, Idaho Power has reviewed the final rule and is in the process of determining how to meet these regulations at the Bridger, Boardman, and Valmy generating plants. The compliance deadline for the new MATS could be as early as 2015, though the current federal Administration has suggested that a one-year extension may be available for utilities where justified.

National Ambient Air Quality Standards (NAAQS) for NOx: In February 2010, the EPA revised the NAAQS for NO₂, establishing a one-hour standard at a level of 100 parts per billion. In connection with the new NAAQS, in February 2012 the EPA issued a final rule designating all of the counties in Idaho, Nevada, Oregon, and Wyoming where Idaho Power owns or has an interest in a natural gas or coal-fired power plant as “unclassifiable/attainment” for NO₂. The EPA indicated it will review the designations after 2015, when three years of air quality monitoring data are available, and may formally designate the counties as attainment or non-attainment for NO₂. A designation of non-attainment may increase the likelihood that Idaho Power would be required to install costly pollution control technology at one or more of its plants. As the designations have not yet been finalized, as of the date of this report Idaho Power is unable to predict the impact of the NAAQS for NO₂ on its operations. However, the costs of installation and implementation of any additional pollution reduction technology could be substantial.

NAAQS for Particulate Matter: On June 29, 2012, the EPA published proposed revisions to the primary and secondary NAAQS for fine particulate matter (PM_2.5). The EPA also proposed revisions to the prevention of significant deterioration permitting program with respect to the proposed NAAQS revisions. The EPA has stated that it plans to finalize the air quality standards by December 2012. The EPA's proposed primary standard for fine particles was between 12 and 13 micrograms per cubic meter (µg/m³), calculated as a three-year average. The EPA proposed to retain the exiting 24-hour primary standard for fine particulate matter at 35 µg/m³. The EPA proposed to remain unchanged the secondary standards for PM_2.5 and would be identical to the primary standards. Once finalized, the revisions to the NAAQS would trigger a process under which states will make recommendation to the EPA regarding designations of attainment or non-attainment. States also will be required to review, modify, and supplement their existing state implementation plans (SIP), which could require the installation of additional controls and requirements for Idaho Power's coal-fired generation plants, depending on the level ultimately finalized. The revised NAAQS would also have an impact on the applicable air permitting requirements for new and modified facilities. The EPA has stated that it plans to issue nonattainment designations by late 2014, with states having until 2020 to comply with the standards. As applicable rules have not yet been finalized and adopted, as of the date of this report Idaho Power is unable to predict the potential financial or operational impact of the proposed NAAQS for fine particulate matter.

NSPS for Greenhouse Gas Emissions for New EGUs: In March 2012, the EPA proposed NSPS limiting CO₂ emissions from new fossil fuel-fired power plants. The proposed requirements, which are limited to new sources, would require new fossil fuel-fired EGUs greater than 25 MW to meet an output-based standard of 1,000 pounds of CO₂ per MWh. The EPA did not propose standards of performance for existing EGUs whose CO₂ emissions increase as a result of installation of pollution controls for conventional pollutants. While Idaho Power does not expect the new NSPS to impact its existing generation facilities, the new rules, if enacted, would impact the cost effectiveness of developing new EGUs.

Clean Air Act - Regional Haze Rules: In accordance with federal regional haze rules under the CAA, coal-fired utility boilers are subject to regional haze - best available retrofit technology (RH BART) if they were built between 1962 and 1977 and affect any Class I areas. This includes all four units at the Jim Bridger plant and the Boardman plant. Under the CAA, states are required to develop a SIP to meet various air quality requirements and submit them to the EPA for approval. The CAA provides that if the EPA deems a SIP submittal to be incomplete or "unapprovable," then the EPA will promulgate a federal implementation plan (FIP) to fill the deemed regulatory gap. In May 2012, the EPA proposed to partially reject Wyoming's regional haze SIP, submitted in January 2011, for NOx reduction at the Jim Bridger plant, instead proposing to substitute the

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EPA's own RH BART determination and FIP. The EPA's primary proposal would result in an acceleration of the installation of selective catalytic reduction (SCR) additions at Bridger Units 1 and 2 to within five years after the FIP, or a SIP revised to be consistent with the proposed FIP, is adopted by the EPA. The EPA has stated that it plans to adopt the FIP, or approve the revised Wyoming SIP, by late 2012. The EPA recognized that this accelerated schedule may create a hardship for the owners of the Jim Bridger plant, including Idaho Power and its customers, and has requested the submission of comments on whether the Wyoming schedule that would not require installation of the SCR on Bridger Units 1 and 2 until 2021 and 2022, respectively, is more appropriate. In August 2012, Idaho Power and PacifiCorp, among other interested parties, submitted comments to the EPA in support of the Wyoming SIP and requesting that the SIP be approved without amendment.

Clean Water Act Section 316(b): In March 2011, the EPA issued a proposed rule that would establish requirements under Section 316(b) of the federal Clean Water Act for all existing power generating facilities and existing manufacturing and industrial facilities that withdraw more than 2 million gallons per day of water from waters of the U.S. and use at least 25 percent of the water they withdraw exclusively for cooling purposes. The proposed rules would establish national requirements applicable to the location, design, construction, and capacity of cooling water intake structures at these facilities by setting requirements that reflect the best technology available for minimizing adverse environmental impact. In June 2012, the EPA released new data, requested further public comment, and announced it plans to finalize the cooling water intake structures rule by June 2013. Based on the qualification criteria, Idaho Power expects that the new requirements would apply to the Jim Bridger plant but is unable to determine the potential increased costs that may result until final rules are issued and it has performed cost studies.

Endangered Species

Endangered Species Act -- Bliss and Lower Salmon Falls Projects:  As part of a settlement agreement for the current license, Idaho Power has finalized a snail protection plan for the Bliss and Lower Salmon Falls projects in cooperation with the U.S. Fish and Wildlife Service (USFWS).  Idaho Power has filed applications with the FERC to amend the licenses for the projects that will maintain operating flexibility at both projects for the remainder of their licenses. The FERC requested formal consultation with the USFWS regarding the license amendments in July 2012. The ESA Section 7 consultation will include two listed snails, the Bliss Rapids snail and the Snake River physa snail. Idaho Power has been working closely with USFWS to develop the necessary biological information for timely completion of the consultation.

Renewable Energy Contracts and Credits

CSPP Contracts: Idaho Power purchases wind power from both CSPP and non-CSPP facilities, including its largest non-CSPP wind power project -- the Elkhorn Valley wind project with a 101 MW nameplate capacity. As of September 30, 2012, Idaho Power had contracts to purchase energy from 26 on-line CSPP wind power projects with a combined nameplate rating of 537 MW.  At that date, Idaho Power also had signed, public utility commission-approved contracts to purchase energy from one CSPP wind project with a combined nameplate rating of 40 MW.  This project is expected to be on-line in December 2012.  In addition to its power purchase arrangements with wind power generators, Idaho Power has contracts for the purchase of power from other renewable generation sources, such as biomass, solar, and small hydroelectric projects. As of September 30, 2012, Idaho Power had 20 MW of solar power generation under contract for purchase. As of September 30, 2012, Idaho Power had the number and nameplate capacity of signed CSPP-related agreements with terms ranging from one to 35 years set forth in the table below. 

Status	Number of CSPP Contracts	Nameplate Capacity (MW)
On-line as of September 30, 2012	102	739
Contracted and projected to come on-line by year-end 2014	7	92
Total	109	831

In August 2012, Idaho Power entered into a settlement stipulation with the developer of wind projects with a planned aggregate nameplate capacity of 116 MW, in connection with Idaho Power's contention that the developer had failed to complete the project in advance of the scheduled operation date required by the power purchase agreements entered into between Idaho Power and the wind projects. The settlement stipulation, which was approved by the IPUC in August 2012, provides that Idaho Power will return to the project developer the letters of credit it held as delay security for the projects, and that the power purchase agreements would be terminated.

REC Sales: Pursuant to an IPUC order, Idaho Power is selling its near-term RECs and returning to Idaho customers their share (shared 95 percent with customers in the Idaho jurisdiction) of those proceeds through the PCA. Idaho Power filed a REC

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Management Plan with the IPUC in December 2009 to address its treatment of future RECs.  Under the REC Management Plan, Idaho Power is selling its near-term RECs while continuing to acquire and hold long-term contractual rights to own RECs for use in meeting future renewable portfolio standards.  For the nine months endedSeptember 30, 2012 and 2011, Idaho Power's REC sales were approximately $4 million and $5 million, respectively. Ordinarily, Idaho Power does not receive the RECs associated with PURPA projects. However, Idaho Power is engaged in proceedings at the IPUC relating to ownership of RECs associated with PURPA projects.

OTHER MATTERS

Critical Accounting Policies and Estimates

IDACORP’s and Idaho Power’s discussion and analysis of their financial condition and results of operations are based upon their condensed consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles.  The preparation of these financial statements requires IDACORP and Idaho Power to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities.  On an ongoing basis, IDACORP and Idaho Power evaluate these estimates, including those estimates related to rate regulation, benefit costs, contingencies, litigation, impairment of assets, income taxes, unbilled revenue, and bad debt.  These estimates are based on historical experience and on other assumptions and factors that are believed to be reasonable under the circumstances, and are the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources.  IDACORP and Idaho Power, based on their ongoing reviews, make adjustments when facts and circumstances dictate.

IDACORP’s and Idaho Power’s critical accounting policies are reviewed by the audit committee of the boards of directors.  These policies have not changed materially from the discussion of those policies included under “Critical Accounting Policies and Estimates” in IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Recently Issued Accounting Pronouncements

There have been no recently issued accounting pronouncements that have had or are expected to have a material impact on IDACORP's or Idaho Power's results of operations or financial condition.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IDACORP and Idaho Power are exposed to market risks, including changes in interest rates, changes in commodity prices, credit risk, and equity price risk.  The following discussion summarizes these risks and the financial instruments, derivative instruments, and derivative commodity instruments sensitive to changes in interest rates, commodity prices, and equity prices that were held at September 30, 2012.

Interest Rate Risk

IDACORP and Idaho Power manage interest expense and short- and long-term liquidity through a combination of fixed rate and variable rate debt.  Generally, the amount of each type of debt is managed through market issuance, but interest rate swap and cap agreements with highly-rated financial institutions may be used to achieve the desired combination.

Variable Rate Debt:  As of September 30, 2012, IDACORP and Idaho Power had $75.5 million and $24.1 million, respectively, in net floating-rate debt. The fair market value of this debt was $75.5 million and $24.1 million, respectively. Assuming no change in financial structure, if variable interest rates were to average one percentage-point higher than the average rate on September 30, 2012, interest rate expense would increase and pre-tax earnings would decrease by approximately $0.8 million for IDACORP and $0.2 million for Idaho Power.

Fixed Rate Debt:  As of September 30, 2012, IDACORP and Idaho Power each had $1.5 billion in fixed rate debt, with a fair market value equal to $1.8 billion.  These instruments are fixed rate and, therefore, do not expose the companies to a loss in earnings due to changes in market interest rates.  However, the fair value of these instruments would increase by approximately $152.9 million for both IDACORP and Idaho Power if market interest rates were to decline by one percentage point from their September 30, 2012 levels.

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Commodity Price Risk

Idaho Power's exposure to changes in commodity prices is related to its ongoing utility operations that produce electricity to meet the demand of its retail electric customers. To supplement its generation resources and balance its supply of power with the demand of its retail customers, Idaho Power participates in the wholesale marketplace. IDACORP’s and Idaho Power’s commodity price risk as of September 30, 2012 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.  Information regarding Idaho Power’s use of derivative instruments to manage commodity price risk can be found in Note 12 – “Derivative Financial Instruments” to the condensed consolidated financial statements included in this report.

Credit Risk

Idaho Power is subject to credit risk based on its activity with market counterparties.  Idaho Power is exposed to this risk to the extent that a counterparty may fail to fulfill a contractual obligation to provide energy, purchase energy, or complete financial settlement for market activities.  Idaho Power mitigates this exposure by actively establishing credit limits; measuring, monitoring, and reporting credit risk using appropriate contractual arrangements; and transferring of credit risk through the use of financial guarantees, cash, or letters of credit.  Idaho Power maintains a current list of acceptable counterparties and credit limits.

The use of performance assurance collateral in the form of cash, letters of credit, or guarantees is common industry practice.  Idaho Power maintains margin agreements relating to its wholesale commodity contracts that allow performance assurance collateral to be requested of and/or posted with certain counterparties.  As of September 30, 2012, Idaho Power had posted $1.2 million of performance assurance collateral.  Should Idaho Power experience a reduction in its credit rating on Idaho Power's unsecured debt to below investment grade, Idaho Power could be subject to requests by its wholesale counterparties to post performance assurance collateral.  Counterparties to derivative instruments and other forward contracts could request immediate payment or demand immediate ongoing full daily collateralization on derivative instruments and contracts in net liability positions.  Based upon Idaho Power's current energy and fuel portfolio and market conditions as of September 30, 2012, the approximate amount of collateral that could be requested upon a downgrade to below investment grade is approximately $4.5 million.  Idaho Power actively monitors the portfolio exposure and the potential exposure to additional requests for performance assurance collateral calls, through sensitivity analysis, to minimize capital requirements.

Idaho Power’s credit risk related to uncollectible accounts as of September 30, 2012 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

Equity Price Risk

IDACORP and Idaho Power are exposed to price fluctuations in equity markets, primarily through their defined benefit pension plan assets, a mine reclamation trust fund owned by an equity-method investment of Idaho Power, and other equity security investments at Idaho Power. IDACORP’s and Idaho Power’s equity price risk as of September 30, 2012 had not changed materially from that reported in Item 7A of IDACORP's and Idaho Power's Annual Report on Form 10-K for the year ended December 31, 2011.

ITEM 4.  CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

IDACORP:  The Chief Executive Officer and the Chief Financial Officer of IDACORP, based on their evaluation of IDACORP’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2012, have concluded that IDACORP’s disclosure controls and procedures are effective as of that date.

Idaho Power:  The Chief Executive Officer and the Chief Financial Officer of Idaho Power, based on their evaluation of Idaho Power’s disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of September 30, 2012, have concluded that Idaho Power’s disclosure controls and procedures are effective as of that date.

Changes in Internal Control Over Financial Reporting

There have been no changes in IDACORP’s or Idaho Power’s internal control over financial reporting during the quarter ended September 30, 2012, that have materially affected, or are reasonably likely to materially affect, IDACORP’s or Idaho Power’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS

Refer to Note 9 - “Contingencies” to the condensed consolidated financial statements included in this report for information regarding certain legal and administrative proceedings in which the registrants are involved.

ITEM 1A.  RISK FACTORS

The factors discussed in Part I - Item 1A - “Risk Factors” in IDACORP’s and Idaho Power’s Annual Report on Form 10-K for the year ended December 31, 2011, could materially affect IDACORP’s and Idaho Power’s business, financial condition, or future results. There have been no material changes from the risk factors set forth in that section. In addition to those risk factors, also see "Forward-Looking Statements" in this report for additional factors that could have a significant impact on IDACORP's or Idaho Power's operations, results of operations, or financial condition and could cause actual results to differ materially from those anticipated in forward-looking statements.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Restrictions on Dividends

A covenant under IDACORP’s credit facility and Idaho Power’s credit facility requires IDACORP and Idaho Power to maintain leverage ratios of consolidated indebtedness to consolidated total capitalization, as defined therein, of no more than 65 percent at the end of each fiscal quarter.  Idaho Power’s Revised Code of Conduct approved by the IPUC on April 21, 2008, states that Idaho Power will not pay any dividends to IDACORP that will reduce Idaho Power’s common equity capital below 35 percent of its total adjusted capital without IPUC approval.  Idaho Power’s ability to pay dividends on its common stock held by IDACORP and IDACORP’s ability to pay dividends on its common stock are limited to the extent payment of such dividends would violate the covenants or Idaho Power’s Revised Code of Conduct.

Idaho Power’s articles of incorporation contain restrictions on the payment of dividends on its common stock if preferred stock dividends are in arrears.  Idaho Power has no preferred stock outstanding.  Further, Idaho Power must obtain approval of the OPUC before it could directly or indirectly loan funds or issue notes or give credit on its books to IDACORP.

See Note 6 - “Common Stock” to the condensed consolidated financial statements included in this report for a further discussion of restrictions on IDACORP’s and Idaho Power’s payment of dividends.

Issuer Purchases of Equity Securities

IDACORP, Inc. did not repurchase any shares of its common stock during the quarter ended September 30, 2012.

ITEM 4.  MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95.1 of this report, which is incorporated herein by reference.

ITEM 5. OTHER INFORMATION

None.

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ITEM 6.  EXHIBITS

Exhibits for IDACORP, Inc. and Idaho Power Company are listed in the Exhibit Index, which is incorporated herein by reference. The agreements filed as exhibits to this Quarterly Report on Form 10-Q are filed to provide information regarding their terms and are not intended to provide any other factual or disclosure information about IDACORP, Idaho Power, or the other parties to the agreements. Some of the agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and (a) should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate; (b) have been qualified by disclosures that were made to the other party, which disclosures are not necessarily reflected in the agreement; (c) may apply standards of materiality in a way that is different from what may be viewed as material to investors; and (d) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

		IDACORP, INC.
		(Registrant)
Date:	November 1, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer
Date:	November 1, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative
			Services and Chief Financial Officer
		IDAHO POWER COMPANY
		(Registrant)
Date:	November 1, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer
Date:	November 1, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Financial Officer

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EXHIBIT INDEX

The following exhibits are filed or furnished, as applicable, with the Quarterly Report on Form 10-Q for the quarter ended September 30, 2012:

		Incorporated by Reference				Included
Exhibit No.	Exhibit Description	Form	File No.	Exhibit No.	Date	Herewith
10.621	Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees					X
10.631	Amendment, dated September 19, 2012, to the Idaho Power Company Security Plan for Senior Management Employees II					X
10.64	First Extension Agreement, dated October 12, 2012, to the Second Amended and Restated Credit Agreement, dated October 26, 2011, among IDACORP, Inc., various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners					X
10.65	First Extension Agreement, dated October 12, 2012, to the Second Amended and Restated Credit Agreement, dated October 26, 2011, among Idaho Power Company, various lenders, Wells Fargo Bank, National Association, as administrative agent, swingline lender, and LC issuer, JPMorgan Chase Bank, N.A., as syndication agent and LC issuer, KeyBank National Association and Union Bank, N.A., as documentation agents, and Wells Fargo Securities, LLC, J.P. Morgan Securities Inc., Keybanc Capital Markets, and Union Bank, N.A. as joint lead arrangers and joint book runners					X
12.1	IDACORP, Inc. Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
12.2	Idaho Power Company Computation of Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges					X
15.1	Letter Re:  Unaudited Interim Financial Information					X
31.1	IDACORP, Inc. Rule 13a-14(a) CEO certification					X
31.2	IDACORP, Inc. Rule 13a-14(a) CFO certification					X
31.3	Idaho Power Rule 13a-14(a) CEO certification					X
31.4	Idaho Power Rule 13a-14(a) CFO certification					X
32.1	IDACORP, Inc. Section 1350 CEO certification					X
32.2	IDACORP, Inc. Section 1350 CFO certification					X
32.3	Idaho Power Section 1350 CEO certification					X
32.4	Idaho Power Section 1350 CFO certification					X
95.1	Mine Safety Disclosures					X
101.INS2	XBRL Instance Document					X
101.SCH2	XBRL Taxonomy Extension Schema Document					X
101.CAL2	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.LAB2	XBRL Taxonomy Extension Label Linkbase Document					X
101.PRE2	XBRL Taxonomy Extension Presentation Linkbase Document					X
101.DEF2	XBRL Taxonomy Extension Definition Linkbase Document					X
1   Management contract or compensatory plan or arrangement
2   Includes the following data files formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Income, Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Cash Flows, and Condensed Consolidated Statements of Comprehensive Income for IDACORP, Inc. and Idaho Power Company; (ii) the Condensed Consolidated Statements of Equity for IDACORP, Inc.; and (iii) the combined Notes to Condensed Consolidated Financial Statements for IDACORP, Inc. and Idaho Power Company.

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EX-10.62

Exhibit 10.62

AMENDMENT

TO THE IDAHO POWER COMPANY

SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES I

The Idaho Power Company Security Plan for Senior Management Employees I, as amended and restated effective November 20, 2008 (the “Plan”) is further amended as set forth below. These amendments shall be effective May 1, 2012.

1.    Section 2.27 is amended to read as follows:

“'Years of Participation' shall be twelve (12) month periods, and portions thereof, which shall begin on the earlier of the date an individual, who has been designated by the Employer, is approved by the Administrative Committee pursuant to Section 3.1, or the date designated by the Administrative Committee, and shall end on the earliest of (i) the Participant's Termination Date, (ii) the date the Participant experiences a change in status, as provided in Sections 3.3 and 3.4, or (iii) December 31, 2004. Partial Years of Participation, if any, shall be rounded up to the next full month and shall be used in determining benefits under this Plan.”

2.    Section 6.6(a)(i) is amended to read as follows:

“A joint and survivor annuity with payments continued to the surviving spouse at an amount equal to 75% of the Participant's benefit.”

APPROVED BY THE COMPENSATION COMMITTEE ON SEPT. 19, 2012

IDAHO POWER COMPANY

By:/s/ J. LaMont Keen_____

Chief Executive Officer

By:/s/ Patrick A. Harrington____

Corporate Secretary

EX-10.63

Exhibit 10.63

AMENDMENT

TO THE IDAHO POWER COMPANY

SECURITY PLAN FOR SENIOR MANAGEMENT EMPLOYEES II

The Idaho Power Company Security Plan for Senior Management Employees II, as amended and restated effective November 30, 2011 (the “Plan”) is further amended as set forth below. These amendments shall be effective May 1, 2012.

1.    The definition of “Final Average Monthly Compensation,” Section 2.15, is amended to read as follows:

“'Final Average Monthly Compensation' shall mean the Compensation received by the Participant during any sixty (60) consecutive months (during the last ten (10) years of employment) for which the Participant's Compensation was the highest, divided by sixty (60). For purposes of determining Final Average Monthly Compensation, annual bonuses shall be included as Compensation in the month in which paid. Final Average Monthly Compensation shall not include any Compensation payable to a Participant pursuant to a written severance agreement with the Employer.”

2.    Section 2.26 is amended to read as follows:

“'Years of Participation' shall be twelve (12) month periods, and portions thereof, which shall begin on the earlier of the date an individual, who has been designated by the Employer, is approved by the Administrative Committee pursuant to Section 3.1, or the date designated by the Administrative Committee, and shall end on the earliest of (i) the Participant's death, (ii) the Participant's Termination Date, (iii) the date the Participant experiences a change in status, as provided in Sections 3.3 and 3.4, or (iv) if available and elected, the effective date of an accelerated distribution under the Security Plan for Senior Management Employees I. Partial Years of Participation, if any, shall be rounded up to the next full month and shall be used in determining benefits under this Plan. Years of Participation under the Security Plan for Senior Management Employees I, if any, shall be included in determining the total Years of Participation.”

3.    Section 5.6.1(a) is amended to read as follows:

“A joint and survivor annuity with payments continued to the surviving spouse at an amount equal to 75% of the Participant's benefit.”

APPROVED BY THE COMPENSATION COMMITTEE ON SEPT. 19, 2012

IDAHO POWER COMPANY

By:/s/ J. LaMont Keen______

Chief Executive Officer

By:/s/ Patrick A. Harrington_____

Corporate Secretary

EX-10.64

Exhibit 10.64

FIRST EXTENSION AGREEMENT

THIS FIRST EXTENSION AGREEMENT, dated as of the October 12, 2012 (this “Agreement”), is made among IDACORP, Inc., an Idaho corporation (the “Borrower”), the Lenders and Wells Fargo Bank, National Association, as administrative agent for the Lenders (the “Administrative Agent”).

RECITALS

A.    The Borrower, the Lenders and the Administrative Agent are parties to that certain Second Amended and Restated Credit Agreement, dated as of October 26, 2011 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Capitalized terms used herein without definition shall have the meanings given to them in the Credit Agreement as they may be modified pursuant to this Agreement.

B.    The Borrower has requested a one-year extension of the Facility Termination Date pursuant to Section 2.21(a) of the Credit Agreement and the Lenders signatory hereto have approved such request pursuant to Section 2.21 of the Credit Agreement.

STATEMENT OF AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

EXTENSION

Pursuant to Section 2.21(a) of the Credit Agreement, the Borrower provided an Extension Notice to the Administrative Agent on September 19, 2012 that, if agreed to by Lenders holding more than fifty percent (50%) of the Aggregate Commitments, would extend the Facility Termination Date for a period of one year from October 26, 2016 to October 26, 2017. As of the date hereof, Lenders (the “Consenting Lenders”) holding more than fifty percent (50%) of the aggregate amount of the Aggregate Commitments have agreed to the extension and, subject to the satisfaction of the conditions in Section 2.21(c) of the Credit Agreement, the Facility Termination Date as to the Consenting Lenders shall be extended to October 26, 2017. Subject to the right of Borrower pursuant to Section 2.21(b) of the Credit Agreement to replace the Commitment of any Non-Consenting Lenders for the remaining duration of the Credit Agreement, the Facility Termination Date as to the Non-Consenting Lenders remains unchanged.

ARTICLE II

CONDITIONS OF EFFECTIVENESS

2.1    The extension of the Facility Termination Date pursuant to Article I shall become effective as of the date (the “Extension Date”) when, and only when, each of the following conditions precedent shall have been satisfied:

(a)The Administrative Agent (or its counsel) shall have received from the Borrower and Lenders holding more than fifty percent (50%) of the aggregate amount of the Aggregate Commitments either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include facsimile or other electronic image scan transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b)The Borrower shall have paid:

(i)to the Administrative Agent, for the account of each Lender agreeing to the extension, an extension fee in the amount of 0.075% of such Lender's Commitment as of the Extension Date, which extension fee once paid will be fully earned and nonrefundable; and

(ii)all other fees and reasonable expenses of the Administrative Agent and the Lenders required under the Credit Agreement and any other Loan Document to be paid on or prior to the Extension Date (including reasonable fees and expenses of counsel) in connection with this Agreement.

(c)The Administrative Agent shall have received a certificate (the statements contained in which shall be true) of a duly authorized officer of the Borrower stating that both before and after giving effect to such extension of the Facility Termination Date (i) no Default has occurred and is continuing and (ii) all representations and warranties contained in Article 5 of the Credit Agreement are true and correct in all material respects on and as of the Extension Date, except for such representations or warranties which by their terms are made as of a specified date, which shall be true and correct as of such specified date.

ARTICLE III

ACKNOWLEDGMENT AND CONFIRMATION OF THE BORROWER

The Borrower hereby confirms and agrees that after giving effect to this Agreement, the Credit Agreement and the other Loan Documents remain in full force and effect and enforceable against it in accordance with their respective terms and shall not be discharged, diminished, limited or otherwise affected in any respect, except as set forth in this Agreement. The Borrower represents and warrants to the Lenders that it has no knowledge of any claims, counterclaims, offsets, or defenses to or with respect to its obligations under the Loan Documents, or if the Borrower has any such claims, counterclaims, offsets, or defenses to the Loan Documents or any transaction related to the Loan Documents, the same are hereby waived, relinquished, and released in consideration of the execution of this Agreement. This acknowledgment and confirmation by the Borrower is made and delivered to induce the Administrative Agent and the Lenders to enter into this Agreement. The Borrower acknowledges that the Administrative Agent and the Lenders would not enter into this Agreement in the absence of the acknowledgment and confirmation contained herein.

ARTICLE IV

GENERAL PROVISIONS

4.1    Full Force and Effect. Except as expressly modified hereby, the Credit Agreement shall continue in full force and effect in accordance with the provisions thereof on the date hereof. As used in the Credit Agreement, “hereinafter,” “hereto,” “hereof,” and words of similar import shall, unless the context otherwise requires, mean the Credit Agreement after giving effect to this Agreement. Any reference to the Credit Agreement or any of the other Loan Documents herein or in any such documents shall refer to the Credit Agreement and Loan Documents as modified hereby. This Agreement is limited as specified and shall not constitute or be deemed to constitute an amendment, modification or waiver of any provision of the Credit Agreement except as expressly set forth herein. This Agreement shall constitute a Loan Document under the terms of the Credit Agreement.

4.2    Severability of Provisions. Any provision in this Agreement that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction.

4.3    Counterparts. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Administrative Agent and the Consenting Lenders and each party has notified the Administrative Agent by facsimile transmission or telephone that it has taken such action; provided that this Agreement shall not be deemed to be effective prior to the first date set forth above. Delivery of an executed counterpart of a signature page of this Agreement by facsimile or other electronic transmission will be effective as delivery of a manually executed counterpart thereof.

4.4    Successors and Assigns. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of the Borrower and the Lenders and their respective successors and assigns.

4.5    Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York.

4.6    Expenses. The Borrower agrees on demand (i) to pay all reasonable fees and expenses of counsel to the Administrative Agent, and (ii) to reimburse the Administrative Agent for all reasonable out-of-pocket costs and expenses, in each case, in connection with the preparation, negotiation, execution and delivery of this Agreement and the other Loan Documents delivered in connection herewith.

4.7    Construction. The headings of the various sections and subsections of this Agreement have been inserted for convenience only and shall not in any way affect the meaning or construction of any of the provisions hereof.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

IDACORP, INC., as Borrower

By:    /s/ Steven R. Keen

Name:    Steven R. Keen

Title: Vice President-Finance and Treasurer    

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Lender, the Issuing Lender, the Swingline Lender and Administrative Agent

By:    /s/ Yann Blindert

Name:    Yann Blindert

Title: Director

JPMORGAN CHASE BANK, N.A., as Syndication Agent and as a Lender

By:    /s/ John E. Zur III    

Name:    John E. Zur III    

Title: Authorized Officer    

KEYBANK NATIONAL ASSOCIATION

By:    /s/ Keven D. Smith

Name:    Keven D Smith    

Title:    Senior Vice President

Union Bank, N.A.

By:    /s/ Jesus Serrano

Name:    Jesus Serrano    

Title:    Vice President

BANK OF AMERICA, N.A.

By:    /s/ Stephen Maloney

Name:    Stephen Maloney    

Title:    Senior Vice President

US BANK, NATIONAL ASSOCIATION, as a lender

By:    /s/ Holland H. Williams

Name:    Holland H. Williams    

Title:    AVP & Portfolio Manager

ROYAL BANK OF CANADA

By:    /s/ Kyle E. Hoffman

Name:    Kyle E. Hoffman    

Title:    Authorized Signatory

THE BANK OF NEW YORK MELLON

By:    /s/ Mark W. Rogers

Name:    Mark W. Rogers

Title:    Vice President

EX-10.65

Exhibit 10.65

FIRST EXTENSION AGREEMENT

THIS FIRST EXTENSION AGREEMENT, dated as of the October 12, 2012 (this “Agreement”), is made among Idaho Power Company, an Idaho corporation (the “Borrower”), the Lenders and Wells Fargo Bank, National Association, as administrative agent for the Lenders (the “Administrative Agent”).

RECITALS

A.    The Borrower, the Lenders and the Administrative Agent are parties to that certain Second Amended and Restated Credit Agreement, dated as of October 26, 2011 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). Capitalized terms used herein without definition shall have the meanings given to them in the Credit Agreement as they may be modified pursuant to this Agreement.

B.    The Borrower has requested a one-year extension of the Facility Termination Date pursuant to Section 2.21(a) of the Credit Agreement and the Lenders signatory hereto have approved such request pursuant to Section 2.21 of the Credit Agreement.

STATEMENT OF AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

EXTENSION

Pursuant to Section 2.21(a) of the Credit Agreement, the Borrower provided an Extension Notice to the Administrative Agent on September 19, 2012 that, if agreed to by Lenders holding more than fifty percent (50%) of the Aggregate Commitments, would extend the Facility Termination Date for a period of one year from October 26, 2016 to October 26, 2017. As of the date hereof, Lenders (the “Consenting Lenders”) holding more than fifty percent (50%) of the aggregate amount of the Aggregate Commitments have agreed to the extension and, subject to the satisfaction of the conditions in Section 2.21(c) of the Credit Agreement, the Facility Termination Date as to the Consenting Lenders shall be extended to October 26, 2017. Subject to the right of Borrower pursuant to Section 2.21(b) of the Credit Agreement to replace the Commitment of any Non-Consenting Lenders for the remaining duration of the Credit Agreement, the Facility Termination Date as to the Non-Consenting Lenders remains unchanged.

ARTICLE II

CONDITIONS OF EFFECTIVENESS

2.1    The extension of the Facility Termination Date pursuant to Article I shall become effective as of the date (the “Extension Date”) when, and only when, each of the following conditions precedent shall have been satisfied:

(a)The Administrative Agent (or its counsel) shall have received from the Borrower and Lenders holding more than fifty percent (50%) of the aggregate amount of the Aggregate Commitments either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include facsimile or other electronic image scan transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b)The Borrower shall have paid:

(i)to the Administrative Agent, for the account of each Lender agreeing to the extension, an extension fee in the amount of 0.075% of such Lender's Commitment as of the Extension Date, which extension fee once paid will be fully earned and nonrefundable; and

(ii)all other fees and reasonable expenses of the Administrative Agent and the Lenders required under the Credit Agreement and any other Loan Document to be paid on or prior to the Extension Date (including reasonable fees and expenses of counsel) in connection with this Agreement.

(c)The Administrative Agent shall have received a certificate (the statements contained in which shall be true) of a duly authorized officer of the Borrower stating that both before and after giving effect to such extension of the Facility Termination Date (i) no Default has occurred and is continuing and (ii) all representations and warranties contained in Article 5 of the Credit Agreement are true and correct in all material respects on and as of the Extension Date, except for such representations or warranties which by their terms are made as of a specified date, which shall be true and correct as of such specified date.

ARTICLE III

ACKNOWLEDGMENT AND CONFIRMATION OF THE BORROWER

The Borrower hereby confirms and agrees that after giving effect to this Agreement, the Credit Agreement and the other Loan Documents remain in full force and effect and enforceable against it in accordance with their respective terms and shall not be discharged, diminished, limited or otherwise affected in any respect, except as set forth in this Agreement. The Borrower represents and warrants to the Lenders that it has no knowledge of any claims, counterclaims, offsets, or defenses to or with respect to its obligations under the Loan Documents, or if the Borrower has any such claims, counterclaims, offsets, or defenses to the Loan Documents or any transaction related to the Loan Documents, the same are hereby waived, relinquished, and released in consideration of the execution of this Agreement. This acknowledgment and confirmation by the Borrower is made and delivered to induce the Administrative Agent and the Lenders to enter into this Agreement. The Borrower acknowledges that the Administrative Agent and the Lenders would not enter into this Agreement in the absence of the acknowledgment and confirmation contained herein.

ARTICLE IV

GENERAL PROVISIONS

4.1    Full Force and Effect. Except as expressly modified hereby, the Credit Agreement shall continue in full force and effect in accordance with the provisions thereof on the date hereof. As used in the Credit Agreement, “hereinafter,” “hereto,” “hereof,” and words of similar import shall, unless the context otherwise requires, mean the Credit Agreement after giving effect to this Agreement. Any reference to the Credit Agreement or any of the other Loan Documents herein or in any such documents shall refer to the Credit Agreement and Loan Documents as modified hereby. This Agreement is limited as specified and shall not constitute or be deemed to constitute an amendment, modification or waiver of any provision of the Credit Agreement except as expressly set forth herein. This Agreement shall constitute a Loan Document under the terms of the Credit Agreement.

4.2    Severability of Provisions. Any provision in this Agreement that is held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as to that jurisdiction, be inoperative, unenforceable, or invalid without affecting the remaining provisions in that jurisdiction or the operation, enforceability, or validity of that provision in any other jurisdiction.

4.3    Counterparts. This Agreement may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Agreement by signing any such counterpart. This Agreement shall be effective when it has been executed by the Borrower, the Administrative Agent and the Consenting Lenders and each party has notified the Administrative Agent by facsimile transmission or telephone that it has taken such action; provided that this Agreement shall not be deemed to be effective prior to the first date set forth above. Delivery of an executed counterpart of a signature page of this Agreement by facsimile or other electronic transmission will be effective as delivery of a manually executed counterpart thereof.

4.4    Successors and Assigns. The terms and provisions of this Agreement shall be binding upon and inure to the benefit of the Borrower and the Lenders and their respective successors and assigns.

4.5    Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York.

4.6    Expenses. The Borrower agrees on demand (i) to pay all reasonable fees and expenses of counsel to the Administrative Agent, and (ii) to reimburse the Administrative Agent for all reasonable out-of-pocket costs and expenses, in each case, in connection with the preparation, negotiation, execution and delivery of this Agreement and the other Loan Documents delivered in connection herewith.

4.7    Construction. The headings of the various sections and subsections of this Agreement have been inserted for convenience only and shall not in any way affect the meaning or construction of any of the provisions hereof.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

IDAHO POWER COMPANY, as Borrower

By:    /s/ Steven R. Keen

Name:    Steven R. Keen

Title: Senior Vice President-Finance and Treasurer    

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Lender, the Issuing Lender, the Swingline Lender and Administrative Agent

By:    /s/ Yann Blindert

Name:    Yann Blindert

Title: Director

JPMORGAN CHASE BANK, N.A., as Syndication Agent and as a Lender

By:    /s/ John E. Zur III    

Name:    John E. Zur III    

Title: Authorized Officer    

KEYBANK NATIONAL ASSOCIATION

By:    /s/ Keven D. Smith

Name:    Keven D Smith    

Title:    Senior Vice President

Union Bank, N.A.

By:    /s/ Michael Agrimis

Name:    Michael Agrimis    

Title:    Vice President

BANK OF AMERICA, N.A.

By:    /s/ Stephen Maloney

Name:    Stephen Maloney    

Title:    Senior Vice President

US BANK, NATIONAL ASSOCIATION, as a lender

By:    /s/ Holland H. Williams

Name:    Holland H. Williams    

Title:    AVP & Portfolio Manager

ROYAL BANK OF CANADA

By:    /s/ Kyle E. Hoffman

Name:    Kyle E. Hoffman    

Title:    Authorized Signatory

THE BANK OF NEW YORK MELLON

By:    /s/ Mark W. Rogers

Name:    Mark W. Rogers

Title:    Vice President

EX-12.1

Exhibit 12.1

IDACORP, Inc.

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)

	Nine months ended September 30,
			Twelve Months Ended
			December 31,
	2012		2011		2010		2009		2008		2007
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	175,331	$	114,729	$	141,729	$	146,737	$	117,614	$	96,003
Adjust for distributed income of equity investees	11,580		2,073		3,522		13,724		5,176		6,064
Fixed charges, as below	65,563		86,758		86,806		79,461		81,172		72,879
Total earnings, as defined	$	252,474	$	203,560	$	232,057	$	239,922	$	203,962	$	174,946
Fixed charges, as defined:
Interest charges1	$	64,311	$	85,097	$	85,840	$	78,457	$	80,282	$	71,946
Rental interest factor	1,252		1,661		966		1,004		890		933
Total fixed charges, as defined	$	65,563	$	86,758	$	86,806	$	79,461	$	81,172	$	72,879
Ratio of earnings to fixed charges	3.85x		2.35x		2.67x		3.02x		2.51x		2.40x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	175,331	$	114,729	$	141,729	$	146,737	$	117,614	$	96,003
Adjust for distributed income of equity investees	11,580		2,073		3,522		13,724		5,176		6,064
Supplemental fixed charges, as below	66,041		87,544		87,870		80,946		82,962		74,631
Total earnings, as defined	$	252,952	$	204,346	$	233,121	$	241,407	$	205,752	$	176,698
Supplemental fixed charges:
Interest charges1	$	64,311	$	85,097	$	85,840	$	78,457	$	80,282	$	71,946
Rental interest factor	1,252		1,661		966		1,004		890		933
Supplemental increment to fixed charges2	478		786		1,064		1,485		1,790		1,752
Total supplemental fixed charges	$	66,041	$	87,544	$	87,870	$	80,946	$	82,962	$	74,631
Supplemental ratio of earnings to fixed charges	3.83x		2.33x		2.65x		2.98x		2.48x		2.37x
1 FIN 48 interest is not included in interest charges.
2 Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-12.2

Exhibit 12.2

Idaho Power Company

Consolidated Financial Information

Ratio of Earnings to Fixed Charges and Supplemental Ratio of Earnings to Fixed Charges

(Thousands of Dollars)

	Nine months ended September 30,
			Twelve Months Ended
			December 31,
	2012		2011			2010			2009		2008			2007
RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	180,943	$	123,351		$	151,347		$	158,080	$	131,715		$	111,965
Adjust for distributed income of equity investees	4,817		(9,018		)	(6,526		)	2,464		(6,772		)	(5,553		)
Fixed charges, as below	65,235		86,249			85,579			78,543		77,568			68,272
Total earnings, as defined	$	250,995	$	200,582		$	230,400		$	239,087	$	202,511		$	174,684
Fixed charges, as defined:
Interest charges1	$	64,008	$	84,626		$	84,651		$	77,580	$	76,711		$	67,386
Rental interest factor	1,227		1,623			928			963		857			886
Total fixed charges, as defined	$	65,235	$	86,249		$	85,579		$	78,543	$	77,568		$	68,272
Ratio of earnings to fixed charges	3.85x		2.33x			2.69x			3.04x		2.61x			2.56x
SUPPLEMENTAL RATIO OF EARNINGS TO FIXED CHARGES
Earnings, as defined:
Income from continuing operations before income taxes	$	180,943	$	123,351		$	151,347		$	158,080	$	131,715		$	111,965
Adjust for distributed income of equity investees	4,817		(9,018		)	(6,526		)	2,464		(6,772		)	(5,553		)
Supplemental fixed charges, as below	65,713		87,035			86,643			80,028		79,358			70,024
Total earnings, as defined	$	251,473	$	201,368		$	231,464		$	240,572	$	204,301		$	176,436
Supplemental fixed charges:
Interest charges1	$	64,008	$	84,626		$	84,651		$	77,580	$	76,711		$	67,386
Rental interest factor	1,227		1,623			928			963		857			886
Supplemental increment to fixed charges2	478		786			1,064			1,485		1,790			1,752
Total supplemental fixed charges	$	65,713	$	87,035		$	86,643		$	80,028	$	79,358		$	70,024
Supplemental ratio of earnings to fixed charges	3.83x		2.31x			2.67x			3.01x		2.57x			2.52x
1 FIN 48 interest is not included in interest charges.
2 Explanation of increment - Interest on the guaranty of American Falls Reservoir District bonds and Milner Dam, Inc. notes which are already included in operation expenses.

EX-15.1

Exhibit 15.1

November 1, 2012

IDACORP, Inc.

Idaho Power Company

Boise, Idaho

We have reviewed, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the unaudited interim financial information of IDACORP, Inc. and subsidiaries and Idaho Power Company and subsidiary for the three-month and nine-month periods ended September 30, 2012 and 2011, as indicated in our reports dated November 1, 2012; because we did not perform audits, we expressed no opinion on that information.

We are aware that our reports referred to above, which are included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, are incorporated by reference in Registration Statement Nos. 333-178124 and 333-178023 on Form S-3 and Registration Statement Nos. 333-65406, 333-125259, 333-143404, and 333-159855 on Form S-8 of IDACORP, Inc. and Registration Statement No. 333-166774 on Form S-3 and Registration Statement No. 333-66496 on Form S-8 of Idaho Power Company.

We also are aware that the aforementioned reports, pursuant to Rule 436(c) under the Securities Act of 1933, are not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act.

/s/ DELOITTE & TOUCHE LLP

Boise, Idaho

EX-31.1

Exhibit 31.1

CERTIFICATION

I, J. LaMont Keen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 1, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Darrel T. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of IDACORP, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 1, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			Executive Vice President - Administrative Services
			and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATION

I, J. LaMont Keen, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 1, 2012	By:	/s/ J. LaMont Keen
			J. LaMont Keen
			Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATION

I, Darrel T. Anderson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Idaho Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 1, 2012	By:	/s/ Darrel T. Anderson
			Darrel T. Anderson
			President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2012 (the "Report"), I, J. LaMont Keen, President and Chief Executive Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. LaMont Keen

J. LaMont Keen

President and Chief Executive Officer

November 1, 2012

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of IDACORP, Inc. (the "Company") on Form 10-Q for the quarter ended September 30, 2012 (the "Report"), I, Darrel T. Anderson, Executive Vice President - Administrative Services and Chief Financial Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

Executive Vice President - Administrative Services

and Chief Financial Officer

November 1, 2012

EX-32.3

Exhibit 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2012 (the "Report"), I, J. LaMont Keen, Chief Executive Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. LaMont Keen

J. LaMont Keen

Chief Executive Officer

November 1, 2012

EX-32.4

Exhibit 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Idaho Power Company (the "Company") on Form 10-Q for the quarter ended September 30, 2012 (the "Report"), I, Darrel T. Anderson, President and Chief Financial Officer of the Company, certify that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Darrel T. Anderson

Darrel T. Anderson

President and Chief Financial Officer

November 1, 2012

EX-95.1

Exhibit 95.1

Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act

The following disclosure is provided pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires certain disclosures by companies that operate mines regulated under the Federal Mine Safety and Health Act of 1977 (Mine Safety Act).

Idaho Power is the parent company of Idaho Energy Resources Co. (IERCo), a joint venturer in Bridger Coal Company (BCC), which mines coal at the Bridger Coal Mine and processing facility (Mine) near Rock Springs, Wyoming.  IERCo owns a one-third interest in BCC. The Mine is comprised of the Bridger surface and underground operations. Day-to-day operation and management of coal mining and processing operations at the Mine are conducted through IERCo's joint venture partner.  Operation of the Mine is regulated by the Mine Safety and Health Administration (MSHA) under the Mine Safety Act.  MSHA inspects the Mine on a regular basis and may issue citations, notices, orders, or any combination thereof, when it believes a violation has occurred under the Mine Safety Act.  Monetary penalties are assessed by MSHA for citations.  The severity and assessment of penalties may be reduced or, in some cases, dismissed through the contest and appeal process. Amounts are reported regardless of whether BCC has challenged or appealed the matter.

The table below summarizes the number of citations, notices, and orders issued, and penalties assessed, by MSHA for the Mine under the indicated provisions of the Mine Safety Act, and other data for the Mine, during the three month period ended September 30, 2012. Legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC) are as of September 30, 2012. Due to timing and other factors, the data may not agree with the mine data retrieval system maintained by MSHA at www.msha.gov.

			Three-month period ended September 30, 2012 (unaudited)
			Surface Mine (MSHA ID No. 4800677)		Underground Mine (MSHA ID No. 4801646)
Mine Safety Act Data:
	Section 104(a) Significant & Substantial Citations (1)		2		20
	Section 104(b) Orders (2)		—		—
	Section 104(d) Citations & Orders (3)		—		3
	Section 107(a) Imminent Danger Orders (4)		—		—
	Section 110(b)(2) Flagrant Violations (5)		—		—
	Received Notice of Pattern of Violations Under Section 104(e)		No		No
	Received Notice of Potential to Have Pattern Under Section 104(e)		No		No
Total Dollar Value of Proposed MSHA Assessments During the Period (in thousands)		$	1	$	65
Legal Actions Pending as of Last Day of Period (6)			3		25
Legal Actions Instituted During Period			1		6
Legal Actions Resolved During Period			—		1
Number of Mining-Related Fatalities			0		0
_______________
(1)  For alleged violations of a mandatory mining safety standard or regulation where such violation contributed to a discrete safety hazard and there exists a reasonable likelihood that the hazard will result in an injury or illness and there is a reasonable likelihood that such injury will be of a reasonably serious nature.
(2)  For alleged failure to totally abate the subject matter of a Mine Safety Act Section 104(a) citation within the period specified in the citation or as subsequently extended.
(3)  For an alleged unwarrantable failure (i.e., aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.
(4)  The existence of any condition or practice in a coal or other mine that could reasonably be expected to cause death or serious physical harm if normal mining operations were permitted to proceed in the area before such condition or practice is eliminated.
(5)  Total number of flagrant violations identified under Section 110(b)(2) of the Mine Safety Act.
(6) All pending legal actions for the surface mine and 20 of the pending legal actions for the underground mine are categorized as contests of proposed civil penalties for violations contained in a citation or order under Subpart C of the FMSHRC Procedural Rules. The remaining five pending legal actions for the underground mine are categorized as contests of citations or orders under Subpart B of the FMSHRC Procedural Rules.

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COMMON STOCK: Level 4 (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2012
Shareholders' equity [Line Items]
Stock Issued During Period, Shares, New Issues	192,814
Remaining shares available under current sales agency agreement	3,000,000
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.47
Dividend Distribution Restriction Amount	$ 913
Continuous equity program
Shareholders' equity [Line Items]
Stock Issued During Period, Shares, New Issues	0
Idaho Power Company
Shareholders' equity [Line Items]
Maximum leverage ratio requirement	0.65
Ratio of Indebtedness to Net Capital	0.49
Dividend Distribution Restriction Amount	$ 806
Dividend Distribution Restriction Threshold	0.35
Ratio of total Capital to total capital and long-term debt	0.52
Preferred Stock, Shares Outstanding	0

XML

SEGMENT INFORMATION: Level 4 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
Segment Reporting Information
Revenues	$ 332,757	$ 308,045	$ 826,788	$ 793,031
Revenues	334,019	309,630	829,862	796,107
Income (loss) attributable to IDACORP, Inc.	92,264	107,414	152,519	157,878
Income (loss) attributable to IDACORP, Inc.	92,069	107,067	152,299	157,708
Total assets	5,207,637		5,207,637		4,960,609
Idaho Power Company
Segment Reporting Information
Revenues	332,757	308,045	826,788	793,031
Income (loss) attributable to IDACORP, Inc.	89,596	104,872	150,125	155,420
IERCo's ownership percentage in Bridger Coal Company			33.00%
Total assets	5,119,384		5,119,384		4,856,839
Idaho Power Company | Idaho Power Company
Segment Reporting Information
Revenues	332,757	308,045	826,788	793,031
Income (loss) attributable to IDACORP, Inc.	89,596	104,872	150,125	155,420
Total assets	5,119,384		5,119,384
All Other
Segment Reporting Information
Revenues	1,262	1,585	3,074	3,076
Income (loss) attributable to IDACORP, Inc.	2,473	2,195	2,174	2,288
Total assets	103,117		103,117
Eliminations
Segment Reporting Information
Revenues	0	0	0	0
Income (loss) attributable to IDACORP, Inc.	0	0	0	0
Total assets	$ (14,864)		$ (14,864)

XML

SEGMENT INFORMATION: Level 3 (Tables)

9 Months Ended

Sep. 30, 2012

Segment Information [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The table below summarizes the segment information for IDACORP’s utility operations and the total of all other segments, and reconciles this information to total enterprise amounts (in thousands of dollars). 

	Utility Operations		All Other		Eliminations			Consolidated Total
Three months ended September 30, 2012:
Revenues	$	332,757	$	1,262	$	—		$	334,019
Net income attributable to IDACORP, Inc.	89,596		2,473		—			92,069
Total assets as of September 30, 2012	5,119,384		103,117		(14,864		)	5,207,637
Three months ended September 30, 2011:
Revenues	$	308,045	$	1,585	$	—		$	309,630
Net income attributable to IDACORP, Inc.	104,872		2,195		—			107,067
Nine months ended September 30, 2012:
Revenues	$	826,788	$	3,074	$	—		$	829,862
Net income attributable to IDACORP, Inc.	150,125		2,174		—			152,299
Nine months ended September 30, 2011:
Revenues	$	793,031	$	3,076	$	—		$	796,107
Net income attributable to IDACORP, Inc.	155,420		2,288		—			157,708